Federal Implementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals, 48208-48483 [2011-17600]
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
40 CFR Parts 51, 52, 72, 78, and 97
[EPA–HQ–OAR–2009–0491; FRL–9436–8]
RIN 2060–AP50
Federal Implementation Plans:
Interstate Transport of Fine Particulate
Matter and Ozone and Correction of
SIP Approvals
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
In this action, EPA is limiting
the interstate transport of emissions of
nitrogen oxides (NOX) and sulfur
dioxide (SO2) that contribute to harmful
levels of fine particle matter (PM2.5) and
ozone in downwind states. EPA is
identifying emissions within 27 states in
the eastern United States that
significantly affect the ability of
downwind states to attain and maintain
compliance with the 1997 and 2006 fine
particulate matter national ambient air
quality standards (NAAQS) and the
1997 ozone NAAQS. Also, EPA is
limiting these emissions through
Federal Implementation Plans (FIPs)
that regulate electric generating units
(EGUs) in the 27 states. This action will
substantially reduce adverse air quality
impacts in downwind states from
emissions transported across state lines.
In conjunction with other federal and
state actions, it will help assure that all
but a handful of areas in the eastern part
of the country achieve compliance with
the current ozone and PM2.5 NAAQS by
the deadlines established in the Clean
Air Act (CAA or Act). The FIPs may not
fully eliminate the prohibited emissions
from certain states with respect to the
1997 ozone NAAQS for two remaining
downwind areas and EPA is committed
to identifying any additional required
upwind emission reductions and taking
any necessary action in a future
rulemaking. In this action, EPA is also
modifying its prior approvals of certain
State Implementation Plan (SIP)
submissions to rescind any statements
that the submissions in question satisfy
the interstate transport requirements of
the CAA or that EPA’s approval of the
SIPs affects our authority to issue
interstate transport FIPs with respect to
the 1997 fine particulate and 1997
ozone standards for 22 states. EPA is
also issuing a supplemental proposal to
request comment on its conclusion that
six additional states significantly affect
downwind states’ ability to attain and
maintain compliance with the 1997
ozone NAAQS.
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SUMMARY:
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This final rule is effective on
October 7, 2011.
ADDRESSES: EPA has established a
docket for this action under Docket ID
No. EPA–HQ–OAR–2009–0491. All
documents in the docket are listed on
the https://www.regulations.gov Web
site. Although listed in the index, some
information is not publicly available,
e.g., CBI or other information whose
disclosure is restricted by statute.
Certain other material, such as
copyrighted material, is not placed on
the Internet and will be publicly
available only in hard copy form.
Publicly available docket materials are
available either electronically through
https://www.regulations.gov or in hard
copy at the EPA Docket Center, EPA
West, Room B102, 1301 Constitution
Avenue, NW., Washington, DC. The
Public Reading Room is open from
8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The
telephone number for the Public
Reading Room is (202) 566–1744, and
the telephone number for the Air Docket
is (202) 566–1742.
FOR FURTHER INFORMATION CONTACT: For
general questions concerning this
action, please contact Ms. Meg Victor,
Clean Air Markets Division, Office of
Atmospheric Programs, Mail Code
6204J, Environmental Protection
Agency, 1200 Pennsylvania Avenue,
NW., Washington, DC 20460; telephone
number: (202) 343–9193; fax number:
(202) 343–2359; e-mail address:
victor.meg@epa.gov. For legal questions,
please contact Ms. Sonja Rodman, U.S.
EPA, Office of General Counsel, Mail
Code 2344A, 1200 Pennsylvania
Avenue, NW., Washington, DC 20460,
telephone (202) 564–4079; e-mail
address: rodman.sonja@epa.gov.
SUPPLEMENTARY INFORMATION:
DATES:
ENVIRONMENTAL PROTECTION
AGENCY
I. Preamble Glossary of Terms and
Abbreviations
The following are abbreviations of
terms used in the preamble.
AQAT Air Quality Assessment Tool
ARP Acid Rain Program
BART Best Available Retrofit Technology
BACT Best Available Control Technology
CAA or Act Clean Air Act
CAIR Clean Air Interstate Rule
CAMx Comprehensive Air Quality Model
with Extensions
CBI Confidential Business Information
CCR Coal Combustion Residuals
CEM Continuous Emissions Monitoring
CENRAP Central Regional Air Planning
Association
CFR Code of Federal Regulations
DEQ Department of Environmental Quality
DSI Dry Sorbent Injection
EGU Electric Generating Unit
FERC Federal Energy Regulatory
Commission
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FGD Flue Gas Desulfurization
FIP Federal Implementation Plan
FR Federal Register
EPA U.S. Environmental Protection Agency
GHG Greenhouse Gas
GW Gigawatts
Hg Mercury
ICR Information Collection Request
IPM Integrated Planning Model
km Kilometers
lb/mmBtu Pounds Per Million British
Thermal Unit
LNB Low-NOX Burners
MACT Maximum Achievable Control
Technology
MATS Modeled Attainment Test Software
μg/m 3 Micrograms Per Cubic Meter
MSAT Mobile Source Air Toxics
MOVES Motor Vehicle Emission Simulator
NAAQS National Ambient Air Quality
Standards
NBP NOX Budget Trading Program
NEI National Emission Inventory
NESHAP National Emissions Standards for
Hazardous Air Pollutants
NOX Nitrogen Oxides
NODA Notices of Data Availability
NSPS New Source Performance Standard
NSR New Source Review
OFA Overfire Air
OSAT Ozone Source Apportionment
Technique
OTAG Ozone Transport Assessment Group
ppb Parts Per Billion
PM2.5 Fine Particulate Matter, Less Than 2.5
Micrometers
PM10 Fine and Coarse Particulate Matter,
Less Than 10 Micrometers
PM Particulate Matter
ppm Parts Per Million
PUC Public Utility Commission
RIA Regulatory Impact Analysis
SCR Selective Catalytic Reduction
SIP State Implementation Plan
SMOKE Sparse Matrix Operator Kernel
Emissions
SNCR Selective Non-catalytic Reduction
SO2 Sulfur Dioxide
SOX Sulfur Oxides, Including Sulfur
Dioxide (SO2) and Sulfur Trioxide (SO3)
TAF Terminal Area Forecast
TCEQ Texas Commission on Environmental
Quality
TIP Tribal Implementation Plan
TLN3 Tangential Low NOX
TPY Tons Per Year
TSD Technical Support Document
WRAP Western Regional Air Partnership
II. General Information
A. Does this action apply to me?
This rule affects EGUs, and regulates
the following groups:
Industry group
NAICS a
Utilities (electric, natural
gas, other systems.) ...
a North
American
2211, 2212, 2213
Industry
Classification
System.
This table is not intended to be
exhaustive, but rather provides a guide
for readers regarding entities likely to be
regulated by this action. This table lists
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
the types of entities that EPA is aware
of that could potentially be regulated.
Other types of entities not listed in the
table could also be regulated. To
determine whether your facility would
be regulated by the proposed rule, you
should carefully examine the
applicability criteria in proposed
§§ 97.404, 97.504, and 97,604.
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B. How is the preamble organized?
I. Preamble Glossary of Terms and
Abbreviations
II. General Information
A. Does this action apply to me?
B. How is the preamble organized?
III. Executive Summary
IV. Legal Authority, Environmental Basis,
and Correction of CAIR SIP Approvals
A. EPA’s Authority for Transport Rule
B. Rulemaking History
C. Air Quality Problems and NAAQS
Addressed
1. Air Quality Problems and NAAQS
Addressed
2. FIP Authority for Each State and
NAAQS Covered
3. Additional Information Regarding CAA
Section 110(a)(2)(D)(i)(I) SIPs for States
in the Transport Rule Modeling Domain
D. Correction of CAIR SIP Approvals
V. Analysis of Downwind Air Quality and
Upwind State Emissions
A. Pollutants Regulated
1. Background
2. Which pollutants did EPA propose to
control for purposes of PM2.5 and Ozone
Transport?
3. Comments and Responses
B. Baseline for Pollution Transport
Analysis
C. Air Quality Modeling to Identify
Downwind Nonattainment and
Maintenance Receptors
1. Emission Inventories
2. Air Quality Basis for Identifying
Receptors
3. How did EPA project future
nonattainment and maintenance for
annual PM2.5, 24-hour PM2.5, and 8-hour
ozone?
D. Pollution Transport From Upwind
States
1. Choice of Air Quality Thresholds
2. Approach for Identifying Contributing
Upwind States
VI. Quantification of State Emission
Reductions Required
A. Cost and Air Quality Structure for
Defining Reductions
1. Summary
2. Background
B. Cost of Available Emission Reductions
(Step 1)
1. Development of Annual NOX and
Ozone-Season NOX Cost Curves
2. Development of SO2 Cost Curves
3. Amount of Reductions That Could Be
Achieved by 2012 and 2014
C. Estimates of Air Quality Impacts (Step
2)
1. Development of the Air Quality
Assessment Tool and Air Quality
Modeling Strategy
2. Utilization of AQAT to Evaluate Control
Scenarios
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3. Air Quality Assessment Results
D. Multi-Factor Analysis and
Determination of State Emission Budgets
1. Multi-Factor Analysis (Step 3)
2. State Emission Budgets (Step 4)
E. Approach to Power Sector Emission
Variability
1. Introduction to Power Sector Variability
2. Transport Rule Variability Limits
F. Variability Limits and State Emission
Budgets: State Assurance Levels
G. How the State Emission Reduction
Requirements Are Consistent With
Judicial Opinions Interpreting the Clean
Air Act
VII. FIP Program Structure to Achieve
Reductions
A. Overview of Air Quality-Assured
Trading Programs
B. Applicability
C. Compliance Deadlines
1. Alignment With NAAQS Attainment
Deadlines
2. Compliance and Deployment of
Pollution Control Technologies
D. Allocation of Emission Allowances
1. Allocations to Existing Units
2. Allocations to New Units
E. Assurance Provisions
F. Penalties
G. Allowance Management System
H. Emissions Monitoring and Reporting
I. Permitting
1. Title V Permitting
2. New Source Review
J. How the Program Structure Is Consistent
With Judicial Opinions Interpreting the
Clean Air Act
VIII. Economic Impacts of the Transport Rule
A. Emission Reductions
B. The Impacts on PM2.5 and Ozone of the
Final SO2 and NOX Strategy
C. Benefits
1. Human Health Benefit Analysis
2. Quantified and Monetized Visibility
Benefits
3. Benefits of Reducing GHG Emissions
4. Total Monetized Benefits
5. How do the benefits in 2012 compare to
2014?
6. How do the benefits compare to the costs
of this final rule?
7. What are the unquantified and nonmonetized benefits of the Transport Rule
emission reductions?
D. Costs and Employment Impacts
1. Transport Rule Costs and Employment
Impacts
2. End-Use Energy Efficiency
IX. Related Programs and the Transport Rule
A. Transition From the Clean Air Interstate
Rule
1. Key Differences Between the Transport
Rule and CAIR
2. Transition From the Clean Air Interstate
Rule to the Transport Rule
B. Interactions With NOX SIP Call
C. Interactions With Title IV Acid Rain
Program
D. Other State Implementation Plan
Requirements
X. Transport Rule State Implementation
Plans
XI. Structure and Key Elements of Transport
Rule Air Quality-Assured Trading
Program Rules
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XII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
G. Executive Order 13045: Protection of
Children From Environmental Health
and Safety Risks
H. Executive Order 13211: Actions That
Significantly Affect Energy Supply,
Distribution, or Use
I. National Technology Transfer and
Advancement Act
J. Executive Order 12898: Federal Actions
To Address Environmental Justice in
Minority Populations and Low-Income
Populations
1. Consideration of Environmental Justice
in the Transport Rule Development
Process and Response to Comments
2. Potential Environmental and Public
Health Impacts Among Populations
Susceptible or Vulnerable to Air
Pollution
3. Meaningful Public Participation
4. Summary
K. Congressional Review Act
L. Judicial Review
III. Executive Summary
The CAA section 110(a)(2)(D)(i)(I)
requires states to prohibit emissions that
contribute significantly to
nonattainment in, or interfere with
maintenance by, any other state with
respect to any primary or secondary
NAAQS. In this final rule, EPA finds
that emissions of SO2 and NOX in 27
eastern, midwestern, and southern
states contribute significantly to
nonattainment or interfere with
maintenance in one or more downwind
states with respect to one or more of
three air quality standards—the annual
PM2.5 NAAQS promulgated in 1997, the
24-hour PM2.5 NAAQS promulgated in
2006, and the ozone NAAQS
promulgated in 1997 (EPA uses the term
‘‘states’’ to include the District of
Columbia in this preamble).
These emissions are transported
downwind either as SO2 and NOX or,
after transformation in the atmosphere,
as fine particles or ozone. This final rule
identifies emission reduction
responsibilities of upwind states, and
also promulgates enforceable FIPs to
achieve the required emission
reductions in each state through costeffective and flexible requirements for
power plants. Each state has the option
of replacing these federal rules with
state rules to achieve the required
amount of emission reductions from
sources selected by the state.
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
Section 110(a)(2)(D)(i)(I) of the CAA
requires the elimination of upwind state
emissions that significantly contribute
to nonattainment or interfere with
maintenance of a NAAQS in another
state. Elimination of these upwind state
emissions may not necessarily, in itself,
fully resolve nonattainment or
maintenance problems at downwind
state receptors. Downwind states also
have control responsibilities because,
among other things, the Act requires
each state to adopt enforceable plans to
attain and maintain air quality
standards. Indeed, states have put in
place measures to reduce local
emissions that contribute to
nonattainment within their borders.
Section 110(a)(2)(D)(i)(I) only requires
the elimination of emissions that
significantly contribute to
nonattainment or interfere with
maintenance of the NAAQS in other
states; it does not shift to upwind states
the responsibility for ensuring that all
areas in other states attain the NAAQS.
The reductions obtained through the
Transport Rule will help all but a few
downwind areas come into attainment
with and maintain the 1997 annual
PM2.5 NAAQS, the 2006 24-hour PM2.5
NAAQS, and the 1997 ozone NAAQS.
With respect to the annual PM2.5
NAAQS, this rule finds that 18 states
have SO2 and annual NOX emission
reduction responsibilities, and this rule
quantifies each state’s full emission
reduction responsibility under section
110(a)(2)(D)(i)(I). See Table III–1 for the
list of these states. With these
reductions, EPA projects that no areas
will have nonattainment or maintenance
concerns with respect to the annual
PM2.5 NAAQS.
With respect to the 24-hour PM2.5
NAAQS, this rule finds that 21 states
have SO2 and annual NOX emission
reduction responsibilities, and this rule
quantifies each state’s full emission
reduction responsibility under
110(a)(2)(D)(i)(I). See Table III–1 for the
list of these states. In all, this rule
requires emission reductions related to
interstate transport of fine particles in
23 states. With these reductions, as
discussed in section VI.D of this
preamble, only one area (LibertyClairton) is projected to remain in
nonattainment, and three other areas
(Chicago,1 Detroit, and Lancaster) are
projected to have remaining
1 This area is not currently designated as
nonattainment for the 24-hour PM2.5 standard. EPA
is portraying the receptors and counties in this area
as a single 24-hour maintenance area based on the
annual PM2.5 nonattainment designation of
Chicago-Gary-Lake County, IL-IN.
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maintenance concerns for the 24-hour
PM2.5 NAAQS.
With respect to the 1997 ozone
NAAQS, this rule finds that 20 states
have ozone-season NOX emission
reduction responsibilities. For 10 of
these states this rule quantifies the
state’s full emission reduction
responsibility under section
110(a)(2)(D)(i)(I).2 For 10 additional
states, EPA quantifies in this rule the
ozone-season NOX emission reductions
that are necessary but may not be
sufficient to eliminate all significant
contribution to nonattainment and
interference with maintenance in other
states.3 See Table III–1 for the complete
list of 20 states required to reduce
ozone-season NOX emissions in this
rule. With the Transport Rule
reductions, only one area (Houston) is
projected to remain in nonattainment,
and one area (Baton Rouge) to have a
remaining maintenance concern with
respect to the 1997 ozone NAAQS. The
10 states upwind of either of these two
areas are the states for which additional
reductions may be necessary to fully
eliminate each state’s significant
contribution to nonattainment and
interference with maintenance, as
discussed in section VI of this
preamble.4
As discussed further below, EPA’s
analysis also demonstrates that six
additional states should be required to
reduce ozone-season NOX emissions.
EPA is issuing a supplemental proposal
to request comment on requiring ozoneseason NOX reductions in these six
states. For five of these six states, EPA’s
analysis identifies the state’s full
emission reduction responsibility under
section 110(a)(2)(D)(i)(I), and for the
remaining one state EPA’s analysis
identifies reductions that are necessary
2 The 10 states for which this rule quantifies the
state’s full responsibility under section
110(a)(2)(D)(i)(I) with respect to the 1997 ozone
NAAQS are Florida, Maryland, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South
Carolina, Virginia, and West Virginia.
3 The 10 states for which this rule quantifies
reductions that are necessary but may not be
sufficient to satisfy the requirements of
110(a)(2)(D)(i)(I) with respect to the 1997 ozone
NAAQS are Alabama, Arkansas, Georgia, Illinois,
Indiana, Kentucky, Louisiana, Mississippi,
Tennessee, and Texas.
4 This preamble uses the term ‘‘significant
contribution’’ only in the context of the CAA
section 110(a)(2)(D)(i)(I) requirement that states
prohibit emissions that ‘‘contribute significantly to
nonattainment’’ in any other state with respect to
any primary or secondary NAAQS. Thus, a
significant contribution, as used in this preamble,
is one that is significant for purposes of CAA
section 110(a)(2)(D)(i)(I) as coming from a particular
state.
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but may not be sufficient to satisfy the
requirements of 110(a)(2)(D)(i)(I).5
On January 19, 2010, EPA proposed
revisions to the 8-hour ozone NAAQS
that the Agency had issued March 12,
2008 (75 FR 2938); the Agency intends
to finalize its reconsideration in the
summer of 2011. EPA intends to
propose a rule to address transport with
respect to the reconsidered 2008 ozone
NAAQS as expeditiously as possible
after reconsideration is completed. EPA
intends to include in that proposed rule
requirements to address any remaining
significant contribution to
nonattainment and interference with
maintenance with respect to the 1997
ozone NAAQS for the states identified
in this final rule, or the associated
supplemental notice of proposed
rulemaking, for which EPA was unable
to fully quantify the emissions that must
be prohibited to satisfy the requirements
of 110(a)(2)(D)(i)(I) with respect to the
1997 ozone NAAQS.
The Act requires EPA to conduct
periodic reviews of each of the NAAQS.
When NAAQS are set or revised, the
CAA requires revision of SIPs to ensure
the standards are met expeditiously and
within relevant timetables in the Act. If
more protective NAAQS are
promulgated, in the case of pollutants
for which interstate transport is
important, additional emission
reductions to address transported
pollution may be required from the
power sector, from other sectors, and
from sources in additional states. EPA
will act promptly to promulgate any
future rules addressing transport with
respect to revised NAAQS.
The Transport Rule requires
substantial near-term emission
reductions in every covered state to
address each state’s significant
contribution to nonattainment and
interference with maintenance
downwind. This rule achieves these
reductions through FIPs that regulate
the power sector using air qualityassured trading programs whose
assurance provisions ensure that
necessary reductions will occur within
every covered state. This remedy
structure is substantially similar to the
preferred trading remedy structure
presented in the proposal. The
Transport Rule’s air quality-assured
trading approach will assure
5 The five states addressed in the supplemental
proposal for which EPA’s analysis identifies the
state’s full reduction responsibility under section
110(a)(2)(D)(i)(I) with respect to the 1997 ozone
NAAQS are Iowa, Kansas, Michigan, Oklahoma,
and Wisconsin. The one state addressed in the
supplemental proposal for which EPA’s analysis
identifies reductions that are necessary but may not
be sufficient to satisfy section 110(a)(2)(D)(i)(I) with
respect to the 1997 ozone NAAQS is Missouri.
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environmental results in each state
while providing market-based flexibility
to covered sources through interstate
trading. The final rule includes four air
quality-assured trading programs: An
annual NOX trading program, an ozoneseason NOX trading program, and two
separate SO2 trading programs (‘‘SO2
Group 1’’ and ‘‘SO2 Group 2’’), as
discussed further in sections VI and VII,
below.
The first phase of Transport Rule
compliance commences January 1, 2012,
for SO2 and annual NOX reductions and
May 1, 2012, for ozone-season NOX
reductions. The second phase of
Transport Rule reductions, which
commences January 1, 2014, increases
the stringency of SO2 reductions in a
number of states as discussed further
below.
EPA projects that with the Transport
Rule, covered EGU will substantially
reduce SO2, annual NOX and ozoneseason NOX emissions, as shown in
Tables III–2 and III–3, below. This rule
generally covers electric generating
units that are fossil fuel-fired boilers
and turbines producing electricity for
sale, as detailed in section VII.B.
EPA is promulgating the Transport
Rule in response to the remand of the
Clean Air Interstate Rule (CAIR) by the
U.S. Court of Appeals for the District of
Columbia Circuit (‘‘Court’’) in 2008.
CAIR, promulgated May 12, 2005 (70 FR
25162), required 29 states to adopt and
submit revisions to their State
Implementation Plans (SIPs) to
eliminate SO2 and NOX emissions that
contribute significantly to downwind
nonattainment of the PM2.5 and ozone
NAAQS promulgated in July 1997. CAIR
covered a similar but not identical set of
states as the Transport Rule. CAIR FIPs
were promulgated April 26, 2006 (71 FR
25328) to regulate electric generating
units in the covered states and achieve
the emission reduction requirements
established by CAIR until states could
submit and obtain approval of SIPs to
achieve the reductions.
In July 2008, the Court found CAIR
and the CAIR FIPs unlawful. North
Carolina v. EPA, 531 F.3d 896 (D.C. Cir.
2008), modified on rehearing, North
Carolina v. EPA, 550 F.3d 1176, 1178
(D.C. Cir. 2008). The Court’s original
decision vacated CAIR. North Carolina,
531 F.3d at 929–30. However, the Court
subsequently remanded CAIR to EPA
without vacatur because it found that
‘‘allowing CAIR to remain in effect until
it is replaced by a rule consistent with
our opinion would at least temporarily
preserve the environmental values
covered by CAIR.’’ North Carolina, 550
F.3d at 1178. The CAIR requirements
have remained in place while EPA has
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developed the Transport Rule to replace
them.
EPA’s approach in the Transport Rule
to measure and address each state’s
significant contribution to downwind
nonattainment and interference with
maintenance is guided by and
consistent with the Court’s opinion in
North Carolina and addresses the flaws
in CAIR identified by the Court therein.
This final rule also responds to
extensive public comments and
stakeholder input received during the
public comment periods in response to
the proposal and subsequent Notices of
Data Availability (NODAs).
In this action, EPA both identifies and
addresses emissions within states that
significantly contribute to
nonattainment or interfere with
maintenance in other downwind states.
In developing this rule, EPA used a
state-specific methodology to identify
emission reductions that must be made
in covered states to address the CAA
section 110(a)(2)(D)(i)(I) prohibition on
emissions that significantly contribute
to nonattainment or interfere with
maintenance in a downwind state. EPA
believes this methodology addresses the
Court’s concern that the approach used
in CAIR was insufficiently statespecific. EPA used detailed air quality
analysis to determine whether a state’s
contribution to downwind air quality
problems is at or above specific
thresholds. A state is covered by the
Transport Rule if its contribution meets
or exceeds one of those air quality
thresholds and the Agency identifies,
using a multi-factor analysis that takes
into account both air quality and cost
considerations, emissions within the
state that constitute the state’s
significant contribution to
nonattainment and interference with
maintenance with respect to the 1997
ozone or the 1997 annual or 2006
24-hour PM2.5 NAAQS. Section
110(a)(2)(D)(i)(I) requires states to
eliminate the emissions that constitute
this ‘‘significant contribution’’ and
‘‘interference with maintenance.’’ 6
In this final rule, EPA determined the
emission reductions required from all
upwind states to eliminate significant
contribution to nonattainment and
interference with maintenance with
respect to the 1997 ozone, 1997 annual
PM2.5, and 2006 24-hour PM2.5 NAAQS,
using, in part, an assessment of modeled
air quality in 2012 and 2014. EPA first
6 In this preamble, EPA uses the terms
‘‘significant contribution’’ and ‘‘interference with
maintenance’’ to refer to the emissions that must be
prohibited pursuant to section 110(a)(2)(D)(i)(I)
because they significantly contribute to
nonattainment or interfere with maintenance of the
NAAQS in another state.
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identified the following two sets of
downwind receptors: (1) Receptors that
EPA projects will have nonattainment
problems; and, (2) receptors that EPA
projects may have difficulty maintaining
the NAAQS based on historic variation
in air quality. To identify areas that may
have problems attaining or maintaining
these air quality standards, EPA
projected a suite of future air quality
design values, based on measured data
during the period 2003 through 2007.
EPA used the average of these future
design values to assess whether an area
will be in nonattainment. EPA used the
maximum projected future design value
to assess whether an area may have
difficulty maintaining the relevant
NAAQS (i.e., whether an area has a
reasonable possibility of being in
nonattainment under adverse emission
and weather conditions). Section V.C of
this preamble details the Transport
Rule’s approach to identify downwind
nonattainment and maintenance areas.
After identifying downwind
nonattainment and/or maintenance
areas, EPA next used air quality
modeling to determine which upwind
states are projected to contribute at or
above threshold levels to the air quality
problems in those areas. Section V.D
details the choice of air quality
thresholds and the approach to
determine how much each upwind state
contributes. States whose contributions
meet or exceed the threshold levels
were analyzed further, as detailed in
section VI, to determine whether they
significantly contribute to
nonattainment or interfere with
maintenance of a relevant NAAQS, and
if so, the quantity of emissions that
constitute their significant contribution
and interference with maintenance.
When EPA proposed this air-quality
and cost-based multi-factor approach to
identify emissions that constitute
significant contribution to
nonattainment and interference with
maintenance from upwind states with
respect to the 1997 ozone, annual PM2.5,
and 2006 24-hour PM2.5 NAAQS, the
Agency indicated that the approach was
designed to be applicable to both
current and potential future ozone and
PM2.5 NAAQS (75 FR 45214). EPA
believes that the Transport Rule’s
approach of using air-quality thresholds
to determine upwind-to-downwindstate linkages and using the air-quality
and cost-based multi-factor approach to
determine the quantity of emissions that
each upwind state must eliminate, i.e.,
the state’s significant contribution to
nonattainment and interference with
maintenance, could serve as a precedent
for quantifying upwind state emission
reduction responsibilities with respect
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to potential future NAAQS, as discussed
further in section VI.A of this preamble.
The Agency further believes that the
final Transport Rule demonstrates the
strong value of this approach for
addressing the role of interstate
transport of air pollution in
communities’ ability to comply with
current and future NAAQS.
EPA thus identified specific emission
reduction responsibilities for each
upwind state found to significantly
contribute to nonattainment or interfere
with maintenance in other states. Using
that information, EPA developed
individual state budgets for emissions
from covered units under the Transport
Rule. The Transport Rule emission
budgets are based on EPA’s state-bystate analysis of each upwind state’s
significant contribution to
nonattainment and interference with
maintenance. Because each state’s
budget is directly linked to this statespecific analysis of the state’s
obligations pursuant to section
110(a)(2)(D)(i)(I), this approach
addresses the Court’s concerns about the
development of CAIR budgets.
In this rule, EPA is finalizing SO2 and
annual NOX budgets for each state
covered for the 24-hour and/or annual
PM2.5 NAAQS and an ozone-season
NOX budget for each state covered for
the ozone NAAQS. A state’s emission
budget is the quantity of emissions that
will remain from covered units under
the Transport Rule after elimination of
significant contribution to
nonattainment and interference with
maintenance in an average year (i.e.,
before accounting for the inherent
variability in power system
operations).7
Baseline power sector emissions from
a state can be affected by changing
weather patterns, demand growth, or
disruptions in electricity supply from
other units or from the transmission
grid. As a consequence, emissions could
vary from year to year even in a state
where covered sources have installed all
controls and taken all measures
necessary to eliminate the state’s
significant contribution to
nonattainment and interference with
maintenance. As described in detail in
7 For the states discussed above for which EPA
has quantified the minimum amount of emission
reductions needed to make measurable progress
toward satisfying the state’s section 110(a)(2)(D)(i)(I)
responsibility, the emission budget is the quantity
of emissions that will remain from covered units
after removal of those emissions.
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sections VI and VII of this preamble, the
Transport Rule accounts for the inherent
variability in power system operations
through ‘‘assurance provisions’’ based
on state-specific variability limits which
extend above the state budgets to form
each state’s ‘‘assurance level.’’ The state
assurance levels take into account the
inherent variability in baseline
emissions from year to year. The final
Transport Rule FIPs will implement
assurance provisions starting in 2012 as
discussed in section VII, below.
The emission reduction requirements
(i.e., the ‘‘remedy’’) EPA is promulgating
in this rule respond to the Court’s
concerns that in CAIR, EPA had not
shown that the emission reduction
requirements would get all necessary
reductions within the state as required
by section 110(a)(2)(D)(i)(I). The
Transport Rule FIPs include assurance
provisions specifically designed to
ensure that no state’s emissions are
allowed to exceed that specific state’s
budget plus the variability limit (i.e., the
state’s assurance level).
Each state’s Transport Rule SO2,
annual NOX, or ozone-season NOX
emission budget is composed of a
number of emission allowances
(‘‘allowances’’) equivalent to the
tonnage of that specific state budget.
Under the Transport Rule FIPs, EPA is
distributing (‘‘allocating’’) allowances
under each state’s budget to covered
units in that state. In this rule, EPA
analyzed each individual state’s
significant contribution to
nonattainment and interference with
maintenance and calculated budgets
that represent each state’s emissions
after the elimination of those prohibited
emissions in an average year. The
methodology used to allocate
allowances to individual units in a
particular state has no impact on that
state’s budget or on the requirement that
the state’s emissions not exceed that
budget plus the variability limit; the
allocation methodology therefore has no
impact on the rule’s ability to satisfy the
statutory mandate of CAA section
110(a)(2)(D)(i)(I).
The Transport Rule’s approach to
allocate emission allowances to existing
units is based on historic heat-input
data, as detailed in section VII.D of this
preamble. The Transport Rule SO2,
annual NOX, and ozone-season NOX
emission allowances each authorize the
emission of one ton of SO2, annual NOX,
or ozone-season NOX emissions,
respectively, during a Transport Rule
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control period, and are the currency in
the Transport Rule’s air quality-assured
trading programs. As discussed in
section IX.A.2 below, EPA is creating
these Transport Rule allowances as
distinct compliance instruments with
no relation to allowances from the CAIR
trading programs. EPA agrees with the
general principle that it is desirable,
where possible, to provide continuity
under successive regulatory trading
programs, for example through the
carryover of allowances from one
program into a subsequent one.
However, EPA is promulgating the
Transport Rule as a court-ordered
replacement for (not a successor to)
CAIR’s trading programs. In light of the
specific circumstances of this case,
including legal and technical issues
discussed in Section IX.A.2 below, the
final rule will not allow any carryover
of banked SO2 or NOX allowances from
the Title IV or CAIR trading programs.
EPA will strongly consider
administrative continuity of this rule’s
trading programs under any future
actions designed to address related
problems of interstate transport of air
pollution. A state may submit a SIP
revision under which the state (rather
than EPA) would determine allocations
for one or more of the Transport Rule
trading programs beginning with vintage
year 2013 or later allowances.8 Section
X of this preamble discusses the final
rule’s provisions for SIP submissions in
detail.
Table III–1 lists states covered by the
Transport Rule for PM2.5 and ozone. It
also, with respect to PM2.5, identifies
whether EPA determined the state was
significantly contributing to
nonattainment or interfering with
maintenance of the 1997 annual PM2.5
NAAQS, the 2006 24-hour PM2.5
NAAQS, or both. As discussed below,
the Transport Rule sorts the states
required to reduce SO2 emissions due to
their contribution to PM2.5 downwind
into two groups of varying reduction
stringency, with ‘‘Group 1’’ states
subject to greater SO2 reduction
stringency than ‘‘Group 2’’ states
starting in 2014. Table III–1 also lists
which SO2 Group each of the states is
in.
8 This final rule allows states to make 2013
allowance allocations through the use of a SIP
revision that is narrower in scope than the other SIP
revisions states can use to replace the FIPs and/or
to make allocation decisions for 2014 and beyond,
as discussed in section X.
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TABLE III–1—STATES THAT SIGNIFICANTLY CONTRIBUTE TO NONATTAINMENT OR INTERFERE WITH MAINTENANCE OF A
NAAQS DOWNWIND IN THE FINAL TRANSPORT RULE
1997 Ozone
NAAQS
1997 Annual
PM2.5 NAAQS
2006 24-Hour
PM2.5 NAAQS
SO2 group
Alabama ...........................................................................................
Arkansas ..........................................................................................
Florida ..............................................................................................
Georgia ............................................................................................
Illinois ...............................................................................................
Indiana .............................................................................................
Iowa .................................................................................................
Kansas .............................................................................................
Kentucky ..........................................................................................
Louisiana ..........................................................................................
Maryland ..........................................................................................
Michigan ...........................................................................................
Minnesota ........................................................................................
Mississippi ........................................................................................
Missouri ............................................................................................
Nebraska ..........................................................................................
New Jersey ......................................................................................
New York .........................................................................................
North Carolina ..................................................................................
Ohio .................................................................................................
Pennsylvania ....................................................................................
South Carolina .................................................................................
Tennessee .......................................................................................
Texas ...............................................................................................
Virginia .............................................................................................
West Virginia ....................................................................................
Wisconsin .........................................................................................
Number of States .............................................................................
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State
X
X
X
X
X
X
............................
............................
X
X
X
............................
............................
X
............................
............................
X
X
X
X
X
X
X
X
X
X
............................
20
X
............................
............................
X
X
X
X
............................
X
............................
X
X
............................
............................
X
............................
............................
X
X
X
X
X
X
X
............................
X
X
18
X
............................
............................
X
X
X
X
X
X
............................
X
X
X
............................
X
X
X
X
X
X
X
............................
X
............................
X
X
X
21
2
............................
............................
2
1
1
1
2
1
............................
1
1
2
............................
1
2
1
1
1
1
1
2
1
2
1
1
1
............................
As explained in this preamble, EPA
has improved and updated both steps of
its significant contribution analysis. It
updated and improved the modeling
platforms and modeling inputs used to
identify states with contributions to
certain downwind receptors that meet
or exceed specified thresholds. It also
updated and improved its analysis for
identifying any emissions within such
states that constitute the state’s
significant contribution to
nonattainment or interference with
maintenance. Therefore, the results of
the analysis conducted for the final rule
differ somewhat from the results of the
analysis conducted for the proposal.9
With respect to the 1997 ozone
NAAQS, the analysis EPA conducted for
the proposal did not identify Wisconsin,
Iowa and Missouri as states that
significantly contribute to
nonattainment or interfere with
maintenance of the ozone NAAQS in
another state. However, the analysis
conducted for the final rule shows that
emissions from these states do
significantly contribute to
nonattainment or interfere with
maintenance of the ozone NAAQS in
9 EPA updated its modeling platforms and
modeling inputs in response to public comments
received on the proposed Transport Rule and
subsequent NODAs and performed other standard
updates.
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another state. EPA is not issuing FIPs
with respect to the 1997 ozone NAAQS
or finalizing ozone season NOX budgets
for these states in this rule. EPA is
publishing a supplemental notice of
proposed rulemaking that will provide
an opportunity for public comment on
our conclusion that these states
significantly contribute to
nonattainment or interfere with
maintenance of the 1997 ozone NAAQS.
In the other direction, the analysis
conducted for the proposal supported
EPA’s conclusion at the time that
Connecticut, Delaware, and the District
of Columbia significantly contributed to
nonattainment or interfered with
maintenance with respect to the 1997
ozone NAAQS, whereas the modeling
for the final rule no longer supports that
conclusion for those states.
Additionally, the modeling conducted
for the final rule identified two ozone
maintenance receptors that were not
identified in the modeling conducted
for the proposal—Allegan County (MI)
and Harford County (MD). Five states
that EPA identified as significantly
contributing to maintenance problems at
the Allegan and/or Harford County
receptors in the modeling for the final
rule uniquely contribute to these
receptors, i.e., absent these receptors the
states would not be covered by the
Transport Rule ozone-season program.
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The five states that uniquely contribute
to these receptors are Iowa, Kansas,
Michigan, Oklahoma, and Wisconsin.
EPA is not issuing FIPs with respect to
the 1997 ozone NAAQS or finalizing
ozone-season NOX budgets for these
states in this rule. EPA is publishing a
supplemental notice of proposed
rulemaking that will provide an
opportunity for public comment on our
conclusion that these states significantly
contribute to nonattainment or interfere
with maintenance of the 1997 ozone
NAAQS.
EPA did not change its methodology
between the proposed Transport Rule
and the final Transport Rule for
identifying upwind states that
significantly contribute to
nonattainment or interfere with
maintenance in other states; nor did
EPA change its methodology for
identifying receptors of concern with
respect to maintenance of the 1997
ozone NAAQS. The final rule’s air
quality modeling identifies the new
states and new receptors described
above based on updated input
information (including emission
inventories), much of which was
provided to EPA through public
comment on the proposal and
subsequent NODAs. Section V of this
preamble details the approach EPA used
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to identify contributing states and
receptors of concern.
With respect to the annual PM2.5
NAAQS, the analysis EPA conducted for
the proposal supported EPA’s
conclusion that the states of Delaware,
the District of Columbia, Florida,
Louisiana, Minnesota, New Jersey, and
Virginia were significantly contributing
to nonattainment and interfering with
maintenance of the annual PM2.5
NAAQS while the final rule’s analysis
does not. Also, with respect to the
24-hour PM2.5 NAAQS, the analysis
conducted for the proposal supported
EPA’s conclusion that the states of
Connecticut, Delaware, the District of
Columbia, and Massachusetts were
significantly contributing to
nonattainment or interfering with
maintenance in other states while the
analysis conducted for the final rule did
not.
In the proposal EPA also requested
comment on whether Texas should be
included in the Transport Rule for
annual PM2.5. EPA’s analysis for the
proposal showed that emissions in
Texas would significantly contribute to
nonattainment or interfere with
maintenance of the annual PM2.5
NAAQS if Texas were not included in
the rule for PM2.5. The proposal did not
include an illustrative budget for Texas
or illustrative allowance allocations.
However, the budgets and allowance
allocations provided for other states in
the proposal were included solely to
illustrate the result of applying EPA’s
proposed methodology for quantifying
significant contribution to the data EPA
proposed to use. EPA provided an
ample opportunity for comment on this
methodology and on the data, including
data regarding emissions from Texas
sources, used in the significant
contribution analysis. EPA received
numerous comments on and corrections
to Texas-specific data. The modeling
conducted for the final rule
demonstrates that Texas significantly
contributes to nonattainment or
interferes with maintenance of the
annual PM2.5 NAAQS in another state.
EPA provided a full opportunity for
comment on whether Texas should be
included in the rule for annual PM2.5, as
well as on the methodology and data
used for the significant contribution
analysis for the final rule. EPA therefore
believes its determination that Texas
must be included in the rule for annual
PM2.5 is a logical outgrowth of its
proposal.
With respect to the 24-hour PM2.5
NAAQS, the analysis EPA conducted for
the proposal did not identify Texas as
a state that significantly contributes to
nonattainment or interferes with
maintenance of 24-hour PM2.5 in
another state. However, the analysis
conducted for the final rule shows that
emissions from Texas do significantly
contribute to nonattainment of the 24hour PM2.5 NAAQS in another state.
EPA is not issuing a FIP for Texas with
respect to the 24-hour PM2.5 NAAQS in
this rule. However, EPA believes that
the FIP for Texas with respect to the
1997 annual PM2.5 NAAQS also
addresses the emissions in Texas that
significantly contribute to
nonattainment and interference with
maintenance of the 2006 24-hour PM2.5
NAAQS in another state.
The final rule, however, does not
cover the states of Connecticut,
Delaware, the District of Columbia,
Florida, Louisiana, or Massachusetts for
annual or 24-hour PM2.5 as the analysis
for the final rule does not support their
inclusion.
The Transport Rule FIPs require the
23 states covered for purposes of the 24hour and/or annual PM2.5 NAAQS to
reduce SO2 and annual NOX emissions
by specified amounts. The FIPs require
the 20 states covered for purposes of the
ozone NAAQS to reduce ozone-season
NOX emissions by specified amounts.
As discussed in detail in section VI,
below, the 23 states covered for the 24hour and/or annual PM2.5 NAAQS are
grouped in two tiers reflecting the
stringency of SO2 reductions required to
eliminate that state’s significant
contribution to nonattainment and
interference with maintenance
downwind. The more-stringent SO2 tier
(‘‘Group 1’’) is comprised of the 16
states indicated in Table III–1, above,
and the less-stringent SO2 tier (‘‘Group
2’’) is comprised of the 7 states
identified in the table. The two SO2
trading programs are exclusive, i.e., a
covered source in a Group 1 state may
use only a Group 1 allowance for
compliance, and likewise a source in a
Group 2 state may use only a Group 2
allowance for compliance. In Group 1
states, the SO2 reduction requirements
become more stringent in the second
phase, which starts in 2014.
In response to the Court’s opinion in
North Carolina, EPA has coordinated
the Transport Rule’s compliance
deadlines with the NAAQS attainment
deadlines that apply to the downwind
nonattainment and maintenance areas.
The Transport Rule requires that all
significant contribution to
nonattainment and interference with
maintenance identified in this action
with respect to the 1997 annual PM2.5
NAAQS and the 2006 24-hour PM2.5
NAAQS be eliminated by no later than
2014, with an initial phase of reductions
starting in 2012 to ensure that
reductions are made as expeditiously as
practicable and, consistent with the
Court’s remand, to ‘‘preserve the
environmental values covered by
CAIR.’’ Sources must comply by January
1, 2012 and January 1, 2014 for the first
and second phases, respectively.
With respect to the 1997 ozone
NAAQS, the Transport Rule requires
NOX reductions starting in 2012 to
ensure that reductions are made as
expeditiously as practicable to assist
downwind state attainment and
maintenance of the standard. Sources
must comply by May 1, 2012. The
Transport Rule’s compliance schedule
and alignment with downwind NAAQS
attainment deadlines are discussed in
detail in section VII below.
Table III–2 shows projected Transport
Rule emissions compared to projected
base case emissions, and Table III–3
shows projected Transport Rule
emissions compared to historical
emissions (i.e., 2005 emissions), for the
power sector in all Transport Rule
states. The ozone-season NOX results
shown in Tables III–2 and III–3 are
based on analysis of the group of 26
states that would be covered for the
ozone-season program if EPA finalizes
the supplemental proposal regarding
ozone-season requirements for Iowa,
Kansas, Michigan, Missouri, Oklahoma,
and Wisconsin.
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TABLE III–2—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSION REDUCTIONS IN COVERED STATES WITH
THE TRANSPORT RULE COMPARED TO BASE CASE WITHOUT TRANSPORT RULE OR CAIR **
[Million tons]
2012
Base case
emissions
SO2 ...........................................................
Annual NOX .............................................
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2012
Transport rule
emissions
7.0
1.4
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Emission
reductions
3.0
1.3
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2014
Base case
emissions
4.0
0.1
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Transport rule
emissions
2.4
1.2
2014
Emission
reductions
3.9
0.2
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TABLE III–2—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSION REDUCTIONS IN COVERED STATES WITH
THE TRANSPORT RULE COMPARED TO BASE CASE WITHOUT TRANSPORT RULE OR CAIR **—Continued
[Million tons]
2012
Base case
emissions
Ozone-Season NOX .................................
2012
Transport rule
emissions
0.7
2012
Emission
reductions
0.6
2014
Base case
emissions
0.1
2014
Transport rule
emissions
0.7
2014
Emission
reductions
0.6
0.1
* Note that numbers may not sum exactly due to rounding.
** As explained in section V.B, EPA’s base case projections for the Transport Rule assume that CAIR is not in place.
Notes: The SO2 and annual NOX emissions
in this table reflect EGUs in the 23 states
covered by this rule for purposes of the 24hour and/or annual PM2.5 NAAQS (Alabama,
Georgia, Illinois, Indiana, Iowa, Kansas,
Kentucky, Maryland, Michigan, Minnesota,
Missouri, Nebraska, New Jersey, New York,
North Carolina, Ohio, Pennsylvania, South
Carolina, Tennessee, Texas, Virginia, West
Virginia, and Wisconsin). The ozone-season
NOX emissions reflect EGUs in the 20 states
covered by this rule for purposes of the ozone
NAAQS (Alabama, Arkansas, Florida,
Georgia, Illinois, Indiana, Kentucky,
Louisiana, Maryland, Mississippi, New
Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, and West Virginia) and the
six states that would be covered for the ozone
NAAQS if EPA finalizes its supplemental
proposal (Iowa, Kansas, Michigan, Missouri,
Oklahoma, and Wisconsin).
TABLE III–3—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSION REDUCTIONS IN COVERED STATES WITH
THE TRANSPORT RULE COMPARED TO 2005 ACTUAL EMISSIONS
[Million tons]
2005
Actual
emissions
SO2 .......................................................................................
Annual NOX .........................................................................
Ozone-Season NOX .............................................................
Notes: The SO2 and annual NOX emissions
in this table reflect EGUs in the 23 states
covered by this rule for purposes of the 24hour and/or annual PM2.5 NAAQS (Alabama,
Georgia, Illinois, Indiana, Iowa, Kansas,
Kentucky, Maryland, Michigan, Minnesota,
Missouri, Nebraska, New Jersey, New York,
North Carolina, Ohio, Pennsylvania, South
Carolina, Tennessee, Texas, Virginia, West
Virginia, and Wisconsin). The ozone-season
NOX emissions reflect EGUs in the 20 states
covered by this rule for purposes of the ozone
NAAQS (Alabama, Arkansas, Florida,
Georgia, Illinois, Indiana, Kentucky,
Louisiana, Maryland, Mississippi, New
Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, and West Virginia) and the
six states that would be covered for the ozone
NAAQS if EPA finalizes its supplemental
proposal (Iowa, Kansas, Michigan, Missouri,
Oklahoma, and Wisconsin).
In addition to the emission reductions
shown above, EPA projects other
2012
Transport rule
emissions
8.8
2.6
0.9
2012
Emission
reductions
from 2005
3.0
1.3
0.6
substantial benefits of the Transport
Rule, as described in section VIII in this
preamble. EPA used air quality
modeling to quantify the improvements
in PM2.5 and ozone concentrations that
are expected to result from the
Transport Rule emission reductions in
2014. The Agency used the results of
this modeling to calculate the average
and peak reduction in annual PM2.5, 24hour PM2.5, and 8-hour ozone
concentrations for monitoring sites in
the Transport Rule covered states
(including the six states for which EPA
issued a supplemental proposal for
ozone-season NOX requirements) in
2014.
For annual PM2.5, the average
reduction across all monitoring sites in
covered states in 2014 is 1.41 microgram
per meter cubed (μg/m3) and the greatest
reduction at a single site is 3.60 μg/m3.
2014
Transport rule
emissions
5.8
1.3
0.3
2014
Emission
reductions
from 2005
2.4
1.2
0.6
6.4
1.4
0.3
For 24-hour PM2.5, the average reduction
across all monitoring sites in covered
states in 2014 is 4.3 μg/m3 and the
greatest reduction at a single site is 11.6
μg/m3. And finally, for 8-hour ozone,
the average reduction across all
monitoring sites in covered states in
2014 is 0.3 parts per billion (ppb) and
the greatest is 3.9 ppb. See section VIII
for further information on air quality
improvements.
EPA estimated the Transport Rule’s
costs and benefits, including effects on
sensitive and vulnerable and
environmental justice communities.
Table III–4, below, summarizes some of
these results. Further discussion of the
results is provided in preamble section
VIII, below, and in the Regulatory
Impact Analysis (RIA). Estimates here
are subject to uncertainties discussed
further in the RIA.
TABLE III–4.—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF THE FINAL TRANSPORT RULE IN 2014
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[Billions of 2007$] a
Transport rule remedy (billions of 2007 $)
Description
3% discount rate
Social costs ......................................................................................................................................
Total monetized benefits b ...............................................................................................................
Net benefits (benefits-costs) ............................................................................................................
a All
$0.81 .........................
$120 to $280 .............
$120 to $280 .............
estimates are for 2014, and are rounded to two significant figures.
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7% discount rate
$0.81.
$110 to $250.
$110 to $250.
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b The total monetized benefits reflect the human health benefits associated with reducing exposure to PM
2.5 and ozone and the welfare benefits associated with improved visibility in Class I areas. The reduction in premature mortalities account for over 90 percent of total monetized
PM2.5 and ozone benefits.
As a result of updated analyses and in
response to public comments, the final
Transport Rule differs from the proposal
in a number of ways. The differences
between proposal and final rule are
discussed throughout this preamble.
Some key changes between proposal
and final rule are that EPA:
• Updated emission inventories
(resulting in generally lower base case
emissions). See section V.C.
• Updated modeling and analysis
tools (including improved alignment
between air quality estimates and air
quality modeling results). See sections V
and VI.
• Updated conclusions regarding
which states significantly contribute to
nonattainment or interfere with
maintenance of the NAAQS in other
states. See Table III–1 and sections V.D
and VI.
• Recalculated state budgets and
variability limits, i.e., state assurance
levels, based on updated modeling. See
section VI.
• Simplified variability limits for oneyear application only. See section VI.E.
• Revised allocation methodology for
existing and new units and revised new
unit set-asides for new units in
Transport Rule states and new units
potentially locating in Indian country.
See section VII.D.
• Changed start of assurance
provisions to 2012 and increased
assurance provision penalties. See
section VII.E.
• Removed opt-in provisions. See
section VII.B
• Added provisions for full and
abbreviated Transport Rule SIP
revisions. See section X.
EPA conducted substantial
stakeholder outreach in developing the
Transport Rule, starting with a series of
‘‘listening sessions’’ in the spring of
2009 with states, nongovernmental
organizations, and industry. EPA
docketed stakeholder-related materials
in the Transport Rule docket (Docket ID
No. EPA–HQ–OAR–2009–0491). The
Agency conducted general
teleconferences on the rule with tribal
environmental professionals, conducted
consultation with tribal governments,
and hosted a webinar for communities
and tribal governments. EPA continued
to provide updates to regulatory
partners and stakeholders through
several conference calls with states as
well as at conferences where EPA
officials often made presentations. The
Agency conducted additional
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stakeholder outreach during the public
comment period. EPA responded to
extensive public comments received
during the public comment periods on
the proposed rule and associated
NODAs.
This Transport Rule is one of a series
of regulatory actions to reduce the
adverse health and environmental
impacts of the power sector. EPA is
developing these rules to address
judicial review of previous rulemakings
and to issue rules required by
environmental laws. Finalizing these
rules will effectuate health and
environmental protection mandated by
Congress while substantially reducing
uncertainty over the future regulatory
obligations of power plants, which will
assist the power sector in planning for
compliance more cost effectively. The
Agency is providing full opportunity for
notice and comment for each rule.
As discussed above, rules to address
transport under revised NAAQS,
including the reconsidered 2008 ozone
NAAQS, may result in additional
emission reduction requirements for the
power sector. In addition, existing Clean
Air Act rules establishing best available
retrofit technology (BART) requirements
and other requirements for addressing
visibility and regional haze may also
result in future state requirements for
certain power plant emission reductions
where needed.
On May 3, 2011 (76 FR 24976), EPA
proposed national emission standards
for hazardous air pollutants from coaland oil-fired electric utility steam
generating units under CAA section
112(d), also called Mercury and Air
Toxics Standards (MATS), and
proposed revised new source
performance standards for fossil fuelfired EGUs under section 111(b). As
discussed in the EPA-led public
listening sessions during February and
March 2011, EPA is preparing to
propose innovative, cost-effective and
flexible greenhouse gas (GHG) emissions
performance standards under section
111 for steam electric generating units,
the largest U.S. source of greenhouse gas
emissions. On April 20, 2011 (76 FR
22174), EPA proposed requirements
under section 316(b) of the Clean Water
Act for existing power generating
facilities, manufacturing and industrial
facilities that withdraw more than two
million gallons per day of water from
waters of the U.S. and use at least
twenty-five percent of that water
exclusively for cooling purposes. On
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June 21, 2010 (75 FR 35128), the Agency
proposed to regulate coal combustion
residuals (CCRs) under the Resource
Conservation and Recovery Act to
address the risks from the disposal of
CCRs generated from the combustion of
coal at electric utilities and independent
power producers.
EPA will coordinate utility-related air
pollution rules with each other and with
other actions affecting the power sector
including these rules from EPA’s Office
of Water and its Office of Resource
Conservation and Recovery to the extent
consistent with legal authority in order
to provide timely information needed to
support regulated sources in making
informed decisions. Use of a small
number of air pollution control
technologies, widely deployed, can
assist with compliance for multiple
rules. EPA also notes that the flexibility
inherent in the allowance-trading
mechanism included in the Transport
Rule affords utilities themselves a
degree of latitude to determine how best
to integrate compliance with the
emission reduction requirements of this
rule and those of the other rules. EPA
will pursue energy efficiency
improvements in the use of electricity
throughout the economy, along with
other federal agencies, states and other
groups, which will contribute to
additional environmental and public
health improvements while lowering
the costs of realizing those
improvements.
IV. Legal Authority, Environmental
Basis, and Correction of CAIR SIP
Approvals
A. EPA’s Authority for Transport Rule
The statutory authority for this action
is provided by the CAA, as amended, 42
U.S.C. 7401 et seq. Section 110(a)(2)(D)
of the CAA, often referred to as the
‘‘good neighbor’’ provision of the Act,
and requires states to prohibit certain
emissions because of their impact on air
quality in downwind states.
Specifically, it requires all states, within
3 years of promulgation of a new or
revised NAAQS, to submit SIPs that
prohibit certain emissions of air
pollutants because of the impact they
would have on air quality in other
states. 42 U.S.C. 7410(a)(2)(D). This
action addresses the requirement in
section 110(a)(2)(D)(i)(I) regarding the
prohibition of emissions within a state
that will significantly contribute to
nonattainment or interfere with
maintenance of the NAAQS in any other
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state. EPA has previously issued two
rules interpreting and clarifying the
requirements of section
110(a)(2)(D)(i)(I). The NOX SIP Call,
promulgated in 1998, was largely
upheld by the U.S. Court of Appeals for
the DC Circuit in Michigan, 213 F.3d
663. CAIR, promulgated in 2005, was
remanded by the DC Circuit in North
Carolina, 531 F.3d 896, modified on
reh’g, 550 F.3d. 1176. These decisions
provide additional guidance regarding
the requirements of section
110(a)(2)(D)(i)(I) and are discussed later
in this notice.
Section 301(a)(1) of the CAA also
gives the Administrator of EPA general
authority to prescribe such regulations
as are necessary to carry out her
functions under the Act. 42 U.S.C.
7601(a)(1). Pursuant to this section, EPA
has authority to clarify the applicability
of CAA requirements. In this action,
among other things, EPA is clarifying
the applicability of section
110(a)(2)(D)(i)(I) by identifying SO2 and
NOX emissions that must be prohibited
pursuant to this section with respect to
the PM2.5 NAAQS promulgated in 1997
and 2006 and the 8-hour ozone NAAQS
promulgated in 1997.
Section 110(c)(1) requires the
Administrator to promulgate a FIP at
any time within 2 years after the
Administrator finds that a state has
failed to make a required SIP
submission, finds a SIP submission to
be incomplete or disapproves a SIP
submission unless the state corrects the
deficiency, and the Administrator
approves the SIP revision, before the
Administrator promulgates a FIP. 42
U.S.C. 7410(c)(1).
Tribes are not required to submit state
implementation plans. However, as
explained in EPA’s regulations outlining
Tribal Clean Air Act authority, EPA is
authorized to promulgate FIPs for
Indian country as necessary or
appropriate to protect air quality if a
tribe does not submit and get EPA
approval of an implementation plan.
See 40 CFR 49.11(a); see also 42 U.S.C.
section 7601(d)(4).
Section 110(k)(6) of the CAA gives the
Administrator authority, without any
further submission from a state, to
revise certain prior actions, including
actions to approve SIPs, upon
determining that those actions were in
error.
B. Rulemaking History
The Transport Rule FIPs will limit the
interstate transport of emissions of NOX
and SO2 within 27 states in the eastern,
midwestern, and southern United States
that affect the ability of downwind
states to attain and maintain compliance
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with the 1997 and 2006 PM2.5 NAAQS
and the 1997 ozone NAAQS.10 Prior to
this Transport Rule, CAIR was EPA’s
most recent regulatory action in a
longstanding series of regulatory
initiatives to address interstate transport
of air pollution. The proposed Transport
Rule preamble provides more
information on EPA actions prior to
CAIR (75 FR 45221–45225).
CAIR, promulgated May 12, 2005 (70
FR 25162), required 29 states to adopt
and submit revisions to their SIPs to
eliminate SO2 and NOX emissions that
contribute significantly to downwind
nonattainment of the PM2.5 and ozone
NAAQS promulgated in 1997. The
states covered by CAIR were similar but
not identical to the states covered by the
Transport Rule. The CAIR FIPs,
promulgated April 26, 2006 (71 FR
25328), regulated electric generating
units in the covered states and achieved
CAIR’s emission reduction requirements
unless or until states had approved SIPs
to achieve the required reductions.
In July 2008, the DC Circuit Court
found CAIR and the CAIR FIPs unlawful
and vacated CAIR. North Carolina, 531
F.3d at 929–30. However, the Court
subsequently remanded CAIR to EPA
without vacatur in order to ‘‘at least
temporarily preserve the environmental
values covered by CAIR.’’ North
Carolina, 550 F.3d at 1178. CAIR
requirements have remained in place
and CAIR’s emission trading programs
have operated while EPA developed
replacement rules in response to the
remand.
By promulgating the Transport Rule
FIPs, EPA is responding to the Court’s
remand of CAIR and the CAIR FIPs and
replacing those rules. The approaches
EPA used in the Transport Rule to
measure and address each state’s
significant contribution to downwind
nonattainment and interference with
maintenance are guided by and
consistent with the Court’s opinion in
North Carolina and address the flaws in
CAIR identified by the Court therein.
By notice of proposed rulemaking
(Federal Implementation Plans To
Reduce Interstate Transport of Fine
Particulate Matter and Ozone, 75 FR
45210; August 2, 2010), EPA proposed
the Transport Rule to identify and limit
NOX and SO2 emissions within 32 states
in the eastern, midwestern, and
southern United States that affect the
ability of downwind states to attain and
maintain compliance with the 1997 and
2006 PM2.5 NAAQS and the 1997 ozone
10 As discussed in section III of this preamble,
EPA is proposing to apply ozone-season NOX
requirements to additional states. If EPA finalizes
that action as proposed, the total number of states
covered by the Transport Rule FIPs would be 28.
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NAAQS. EPA proposed to achieve the
emission reductions under FIPs, which
states may choose to replace by
submitting SIPs for EPA approval. EPA
proposed to limit emissions by
regulating electric generating units in
the 32 states with interstate emission
trading programs and assurance
provisions to ensure the required
reductions occur in each covered state.
EPA also requested comment on two
alternative FIP remedies.
EPA supplemented the Transport
Rule record with additional information
relevant to the rulemaking in three
NODAs for which EPA requested
comments:
• Notice of Data Availability
Supporting Federal Implementation
Plans to Reduce Interstate Transport of
Fine Particulate Matter and Ozone (75
FR 53613; September 1, 2010). This
NODA provided an updated database of
unit-level characteristics of EGUs
included in EPA modeling, an updated
version of the power sector modeling
platform EPA used to support the final
rule, and other input assumptions and
data EPA provided for public review
and comment.
• Notice of Data Availability
Supporting Federal Implementation
Plans To Reduce Interstate Transport of
Fine Particulate Matter and Ozone:
Revisions to Emission Inventories (75
FR 66055; October 27, 2010). This
NODA provided additional information
relevant to the rulemaking, including
updated emission inventory data for
2005, 2012 and 2014 for several
stationary and mobile source inventory
components.
• Notice of Data Availability for
Federal Implementation Plans To
Reduce Interstate Transport of Fine
Particulate Matter and Ozone: Request
for Comment on Alternative
Allocations, Calculation of Assurance
Provision Allowance Surrender
Requirements, New-Unit Allocations in
Indian Country, and Allocations by
States (76 FR 1109; January 7, 2011).
This NODA provided additional
information relevant to the rulemaking,
including emissions allowance
allocations for existing units calculated
using two alternative methodologies,
data supporting those calculations,
information about an alternative
approach to calculation of assurance
provision allowance surrender
requirements, allocations for new units
locating in Indian country in Transport
Rule states in the future, and provisions
for states to submit SIPs providing for
state allocation of allowances in the
Transport Rule trading programs.
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C. Air Quality Problems and NAAQS
Addressed
1. Air Quality Problems and NAAQS
Addressed
a. Fine Particles
Fine particles are associated with a
number of serious health effects
including premature mortality,
aggravation of respiratory and
cardiovascular disease (as indicated by
increased hospital admissions,
emergency room visits, health-related
absences from school or work, and
restricted activity days), lung disease,
decreased lung function, asthma attacks,
and certain cardiovascular problems. In
addition to effects on public health, fine
particles are linked to a number of
public welfare effects, including (1)
Reduced visibility (haze) in scenic
areas, (2) effects caused by particles
settling on ground or water, such as:
making lakes and streams acidic,
changing the nutrient balance in coastal
waters and large river basins, depleting
the nutrients in soil, damaging sensitive
forests and farm crops, and affecting the
diversity of ecosystems, and (3) staining
and damaging of stone and other
materials, including culturally
important objects such as statues and
monuments.
In 1997, EPA revised the NAAQS for
PM to add new annual and 24-hour
standards for fine particles, using PM2.5
as the indicator (62 FR 38652). These
revisions established an annual
standard of 15 μg/m3 and a 24-hour
standard of 65 μg/m3. During 2006, EPA
revised the air quality standards for
PM2.5. The 2006 standards decreased the
level of the 24-hour fine particle
standard from 65 μg/m3 to 35 μg/m3,
and retained the annual fine particle
standard at 15 μg/m3.
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b. Ozone
Short-term (1- to 3-hour) and
prolonged (6- to 8-hour) exposures to
ambient ozone have been linked to a
number of adverse health effects. At
sufficient concentrations, short-term
exposure to ozone can irritate the
respiratory system, causing coughing,
throat irritation, and chest pain. Ozone
can reduce lung function and make it
more difficult to breathe deeply.
Breathing may become more rapid and
shallow than normal, thereby limiting a
person’s normal activity. Ozone also can
aggravate asthma, leading to more
asthma attacks that may require a
doctor’s attention and the use of
additional medication. Increased
hospital admissions and emergency
room visits for respiratory problems
have been associated with ambient
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ozone exposures. Longer-term ozone
exposure can inflame and damage the
lining of the lungs, which may lead to
permanent changes in lung tissue and
irreversible reductions in lung function.
A lower quality of life may result if the
inflammation occurs repeatedly over a
long time period (such as months, years,
or a lifetime). There is also
epidemiological evidence indicating a
correlation between short-term ozone
exposure and premature mortality.
In addition to causing adverse health
effects, ozone affects vegetation and
ecosystems, leading to reductions in
agricultural crop and commercial forest
yields; reduced growth and survivability
of tree seedlings; and increased plant
susceptibility to disease, pests, and
other environmental stresses (e.g., harsh
weather). In long-lived species, these
effects may become evident only after
several years or even decades and have
the potential for long-term adverse
impacts on forest ecosystems. Ozone
damage to the foliage of trees and other
plants can also decrease the aesthetic
value of ornamental species used in
residential landscaping, as well as the
natural beauty of our national parks and
recreation areas. In 1997, at the same
time we revised the PM2.5 standards,
EPA issued its final action to revise the
NAAQS for ozone (62 FR 38856) to
establish new 8-hour standards. In this
action published on July 18, 1997, we
promulgated identical revised primary
and secondary ozone standards that
specified an 8-hour ozone standard of
0.08 parts per million (ppm).
Specifically, the standards require that
the 3-year average of the fourth highest
24-hour maximum 8-hour average ozone
concentration may not exceed 0.08 ppm.
In general, the 8-hour standards are
more protective of public health and the
environment and more stringent than
the pre-existing 1-hour ozone standards.
On March 12, 2008, EPA published a
revision to the 8-hour ozone standard,
lowering the level from 0.08 ppm to
0.075 ppm. On September 16, 2009,
EPA announced it would reconsider
these 2008 ozone standards. The
purpose of the reconsideration is to
ensure that the ozone standards are
clearly grounded in science, protect
public health with an adequate margin
of safety, and are sufficient to protect
the environment. EPA proposed
revisions to the standards on January 19,
2010 (75 FR 2938) and anticipates
issuing final standards soon.
c. Which NAAQS does this rule
address?
This action addresses the
requirements of CAA section
110(a)(2)(D)(i)(I) as they relate to:
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(1) The 1997 annual PM2.5 standard,
(2) The 2006 24-hour PM2.5 standard,
and
(3) The 1997 ozone standard.
The original CAIR and CAIR FIP
rules, which pre-dated the 2006 PM2.5
standards, addressed the 1997 ozone
and 1997 PM2.5 standards only.
In this action, EPA fully addresses, for
the states covered by this rule, the
requirements of CAA section
110(a)(2)(D)(i)(I) for the annual PM2.5
standard of 15 μg/m3 and the 24-hour
standard of 35 μg/m3. For the 1997 8hour ozone standard of 0.08 ppm, EPA
fully addresses the CAA section
110(a)(2)(D)(i)(I) requirements for some
states covered by this rule, but for the
remaining states EPA is conducting
further analysis to determine whether
further requirements are needed, as
discussed in section III of this preamble.
This action does not address the CAA
section 110(a)(2)(D)(i)(I) requirements
for the revised ozone standards
promulgated in 2008. These standards
are currently under reconsideration. We
are, however, actively conducting the
technical analyses and other work
needed to address interstate transport
for the reconsidered ozone standard as
soon as possible. We intend to issue as
soon as possible a proposal to address
the transport requirements with respect
to the reconsidered standard.
This action addresses these CAA
transport requirements through
reductions in annual emissions of SO2
and NOX, and through reductions in
ozone-season NOX. The rationale for
these reductions is discussed in detail
later in the preamble.
d. Public Comments
EPA received comments on two issues
related to the NAAQS regulated under
the proposed FIPs.
A number of commenters believed
that EPA’s approach to ozone was
inadequate, and that EPA should not
have based the proposed requirements
on the 1997 ozone NAAQS. These
commenters cited EPA’s 2008 revision
to the standard which lowered the
standard to 75 ppb, and noted that
EPA’s January 2010 proposal for
reconsidered ozone NAAQS would, if
finalized, further lower the primary
NAAQS from 75 ppb to a value between
60 and 70 ppb. Accordingly, many of
the commenters believed that EPA
should have considered the 75 ppb level
to be the maximum possible value
moving forward, and that EPA should
have used a value no greater than 75
ppb in its analysis.
EPA agrees with commenters that
EPA and states should address interstate
transport with respect to the tighter
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ozone NAAQS as quickly as possible.
EPA, as commenters noted, intends to
propose a second rule to address
interstate transport of ozone that will be
appropriately configured for the revised
level of the ozone NAAQS after
reconsideration of the 2008 standard is
finalized. EPA is mindful of the need for
SIPs to provide for continuing ozone
progress to meet the 75 ppb level of the
2008 NAAQS, or possibly lower levels
based on the reconsideration. EPA
believes that the ozone-season NOX
requirements of this rule will provide
important initial assistance to states in
this regard.
Some commenters questioned
whether EPA had given states the
opportunity to provide SIPs addressing
transport under the 2006 PM2.5 NAAQS,
and thus questioned the appropriateness
of the issuance of FIPs addressing those
NAAQS. Those comments, and EPA’s
response, are discussed in detail in
section IV.C.2.
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2. FIP Authority for Each State and
NAAQS Covered
The CAA requires and authorizes EPA
to promulgate each of the Federal
Implementation Plans in this final rule.
Section 110(c)(1) of the CAA requires
the Administrator to promulgate a FIP at
any time within 2 years after the
Administrator takes one of three distinct
actions: (1) She finds that a state has
failed to make a required SIP
submission; (2) she finds a SIP
submission to be incomplete; or (3) she
disapproves a SIP submission. Once the
Administrator has taken one of these
actions with respect to a specific state’s
110(a)(2)(D)(i)(I) obligation for a specific
NAAQS, she has a legal obligation to
promulgate a FIP to correct the SIP
deficiency within 2 years. EPA is
relieved of the obligation to promulgate
a FIP only if two events occur before the
FIP is promulgated: (1) The state
submits a SIP correcting the deficiency;
and (2) the Administrator approves the
SIP revision. 42 U.S.C. 7410(c)(1).11
11 The CAA provides that EPA is not relieved of
its obligation to promulgate FIPs unless the state
submits a SIP that corrects the deficiency and EPA
approves the SIP. Nonetheless, in the preamble to
the proposed rule, EPA indicated that for states not
covered by CAIR which had 110(a)(2)(D)(i)(I) SIPs
pending at the time of proposal, EPA would finalize
the FIP only if EPA determined the submission was
incomplete or disapproved the SIP submission. The
only two states covered by this rule but not covered
by CAIR are Kansas and Nebraska. Both Kansas and
Nebraska are covered by this rule based only on
their significant contribution to nonattainment or
interference with maintenance of the 2006 PM2.5
NAAQS. EPA has not received a 110(a)(2)(D)(i)(I)
submission from Nebraska with respect to the
requirements of the 2006 PM2.5 NAAQS. EPA
disapproved a SIP submission from Kansas with
respect to the requirements of 110(a)(2)(D)(i)(I) for
the 2006 PM2.5 NAAQS.
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For each FIP in this rule,12 EPA either
has found that the state has failed to
make a required 110(a)(2)(D)(i)(I) SIP
submission, or has disapproved a SIP
submission.13 In addition, EPA has
determined, in each case, that there has
been no approval by the Administrator
of a SIP submission correcting the
deficiency prior to promulgation of the
FIP. EPA’s obligation to promulgate a
FIP arose when the finding of failure to
submit or disapproval was made, and in
no case has it been relieved of that
obligation.
Some commenters argued that EPA
was relieved of its obligation to
promulgate FIPs when it approved the
CAIR SIPs for certain states. As an
initial matter, EPA notes that this
argument applies only to EPA’s
authority to promulgate FIPs with
respect to the 1997 PM2.5 and/or 1997
ozone NAAQS for a subset of states
covered by the CAIR. It does not apply
to EPA’s authority to promulgate FIPs
for the 2006 PM2.5 NAAQS which was
not addressed in CAIR. It also does not
apply to EPA’s authority to promulgate
FIPs for the 1997 ozone and 1997 PM2.5
NAAQS for states that remain subject to
the CAIR FIPs, including the states that
received EPA approval of abbreviated
CAIR SIPs which allowed the states to
allocate allowances while remaining
subject to the CAIR FIPs.14
Further, the CAIR SIP approvals do
not eliminate EPA’s obligation and
authority to promulgate a FIP to address
the requirements of 110(a)(2)(D)(i)(I)
because the Court in North Carolina v.
EPA, 531 F.3d 896 (D.C. Cir. 2008)
found that compliance with CAIR does
not satisfy the requirement that each
state prohibit all emissions within the
state that significantly contribute to
nonattainment or interfere with
maintenance in another state. The
Court’s finding that CAIR was unlawful
because it did not make measureable
progress towards the statutory mandate
of section 110(a)(2)(D)(i)(I) meant that
the CAIR SIPs were not adequate to
satisfy that mandate. The CAIR SIPs
thus do not correct the SIP deficiencies
identified in the 2005 findings of failure
12 In this action, EPA is issuing 59 FIPs. EPA is
issuing 20 FIPs to remedy SIP deficiencies relating
to the 110(a)(2)(D)(i)(I) requirements for the 1997
ozone NAAQS. EPA is also issuing 18 FIPs to
remedy SIP deficiencies relating to the 1997 PM2.5
NAAQS. Finally, EPA is issuing 21 FIPs to remedy
SIP deficiencies relating to the 2006 PM2.5 NAAQS.
13 The specific findings made and actions taken
by EPA are described in greater detail in the TSD
entitled ‘‘Status of CAA 110(a)(2)(D)(i)(I) SIPs.’’
14 States may also have received approval to
expand the applicability of the CAIR NOX ozone
season program to include all units subject to the
NOX Budget Program, allow opt-ins, or provide for
distribution of a Compliance Supplement Pool
under the CAIR NOX (annual) program.
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48219
to submit. The SIPs remained in force
for the limited purpose allowed by the
Court—that is, to achieve interim
reductions until EPA promulgated a rule
to replace CAIR. Given the flaws the
court identified with CAIR, EPA’s
approval of a CAIR SIP does not relieve
it of the obligation to promulgate FIPs
created under section 110(c)(1) of the
CAA.
Further, to avoid any confusion, EPA
has decided to correct, in this notice,
the full CAIR SIP approvals for states
covered by this rule and the CAA
110(a)(2)(D)(i) SIP approvals for states
covered by CAIR to rescind any
statements suggesting that the SIP
submissions satisfied or relieved states
of the obligation to submit SIPs to
satisfy the requirements of section
110(a)(2)(D)(i)(I) or that EPA was
relieved of its obligation and authority
to promulgate FIPs under
110(a)(2)(D)(I)(i).
Some commenters further argued that
states should be given additional time,
following promulgation of the Transport
Rule, to submit a SIP to meet the
requirements of section 110(a)(2)(D)(i)(I)
and that CAIR should remain in place
in the meantime. Some commenters
specifically suggested that EPA restart
the ‘‘FIP clock’’ 15 to give states this
additional time. EPA does not interpret
the CAA as giving it authority to extend
the deadline for SIP submissions or
restart the FIP clock. And nothing in the
Act requires EPA to give the states
another opportunity, following
promulgation of the Transport Rule, to
promulgate a SIP before EPA
promulgates a FIP. The plain language
of section 110(a)(1) of the Act requires
the submission of SIPs that meet the
requirements of 110(a)(2)(D)(i)(I) within
3 years after the promulgation of or
revision of a primary NAAQS. See 42
U.S.C. 7410(a)(1). Section
110(a)(2)(D)(i)(I) SIPs for the 1997 ozone
and PM2.5 NAAQS were due in 2000
and 110(a)(2)(D)(i)(I) SIPs for the 2006
PM2.5 NAAQS were due in 2009. While
the statute gives EPA authority to
prescribe a shorter period of time for
states to make these SIP submissions, it
does not give EPA authority to extend
the 3-year deadline established by the
Act. See 42 U.S.C. 7410(a)(1). The plain
language of section 110(c)(1) of the Act,
in turn, provides that EPA shall
promulgate a FIP at any time within 2
years after the Administrator makes a
finding of failure to make a required SIP
15 ‘‘FIP clock’’ is a term used to describe EPA’s
responsibility found in CAA Section 110(c)(1) to
promulgate a FIP within 2 years after either:
Finding that a state has not submitted a required
SIP revision or that a submitted SIP revision is
incomplete; or disapproving a SIP revision.
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submission of disapproves, in whole or
in part, a SIP submission. See 42 U.S.C.
7410(c)(1). EPA does not have authority
to set aside the specific deadlines
established in the statute, and neither
provision allows for the deadlines to be
extended or to run from promulgation
by EPA of a rule to quantify the state’s
specific obligations pursuant to section
110(a)(2)(D)(i)(I). The Act does not
require EPA to promulgate a rule or
issue guidance regarding the specific
requirements of section 110(a)(2)(D)(i)(I)
in advance of the SIP submittal
deadline, much less require EPA to
promulgate such a rule a specific
amount of time before the SIP submittal
deadline. For these reasons, EPA has
neither authority to alter the SIP
submittal deadline nor authority to alter
the statute provision regarding when
EPA’s obligation to promulgate a FIP is
triggered.
Finally, EPA does not believe it
would be appropriate, in light of the
Court’s decision in North Carolina, to
establish a lengthy transition period to
the rule that will replace CAIR. The
Court decision remanding CAIR without
vacatur stressed the court’s conclusion
that CAIR was deeply flawed and
emphasized EPA’s obligation to remedy
those flaws expeditiously. North
Carolina, 550 F.3d 1176. Although the
Court did not set a specific deadline for
corrective action, the Court took care to
note that the effect of its opinion would
not be delayed ‘‘indefinitely’’ and that
petitioners could bring a mandamus
petition if EPA were to fail to modify
CAIR in a manner consistent with its
prior opinion. Id. Given the Court’s
emphasis on remedying CAIR’s flaws
expeditiously, EPA does not believe it
would be appropriate to establish a
lengthy transition period to the rule
which is to replace CAIR.
obligations to address the ‘‘significant
contribution’’ and ‘‘interference with
maintenance’’ requirements by
complying with the requirements in this
rule. With regard to the 1997 ozone
NAAQS, EPA believes that states that
are included in this 38 state modeling
domain will meet their section
110(a)(2)(D)(i)(I) obligations to address
the ‘‘significant contribution’’ and
‘‘interference with maintenance’’
requirements by complying with the
requirements in this rule, except for the
10 states found to significantly
contribute to nonattainment or
interference of maintenance in either
Houston or Baton Rouge (i.e., Alabama,
Arkansas, Georgia, Illinois, Indiana,
Kentucky, Louisiana, Mississippi,
Tennessee, and Texas). States that are in
the 38 state modeling domain, and that
are not found to be contributing
significantly to nonattainment or
interfering with maintenance for any
NAAQS evaluated in the modeling for
the final rule, could rely on this analysis
as technical support that their existing
or future interstate transport SIP
submittals are adequate to address the
transport requirements of
110(a)(2)(D)(i)(I). For example, this rule
finds that South Carolina significantly
contributes to nonattainment and
interferes with maintenance of the 1997
ozone NAAQS and the 1997 PM2.5
NAAQS in downwind states. The
technical support for the rule does not
show that South Carolina significantly
contributes to nonattainment or
interferes with maintenance of the 2006
PM2.5 NAAQS in downwind states. EPA
believes that South Carolina can make a
negative declaration concluding that the
state does not significantly contribute to
nonattainment or interfere with
maintenance in other states with regard
to the 2006 PM2.5 NAAQS.
3. Additional Information Regarding
CAA Section 110(a)(2)(D)(i)(I) SIPs for
States in the Transport Rule Modeling
Domain
This final rule quantifies out-of-state
contributions for the 38 states that are
fully contained within the 12 kilometers
(km) eastern U.S. modeling domain.
EPA is making no specific finding for
states that are not fully contained within
the eastern 12 km modeling domain.
EPA did not conduct a contribution
analysis or make any specific finding for
New Mexico, Colorado, Wyoming, and
Montana since they are only partially
contained within the 12 km modeling
domain. With regard to the 1997 PM2.5
NAAQS and 2006 PM2.5 NAAQS, EPA
believes that states that are included in
this 38 state modeling domain will meet
their section 110(a)(2)(D)(i)(I)
D. Correction of CAIR SIP Approvals
In this action, EPA is also correcting
its prior approvals of CAIR related SIP
submissions and CAA 110(a)(2)(D)(i)
SIP submissions from Alabama,
Arkansas, Connecticut, Florida, Georgia,
Illinois, Indiana, Iowa, Kentucky,
Louisiana, Maryland, Massachusetts,
Minnesota, Mississippi, Missouri, New
York, North Carolina, Ohio,
Pennsylvania, South Carolina, Virginia
and West Virginia to rescind any
statements that the SIP submissions
either satisfy or relieve the state of the
obligation to submit a SIP to satisfy the
requirements of section 110(a)(2)(D)(i)(I)
with respect to the 1997 ozone and/or
1997 PM2.5 NAAQS or any statements
that EPA’s approval of the SIP
submissions either relieve EPA of the
obligation to promulgate a FIP or
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remove EPA’s authority to promulgate a
FIP. This action is based on EPA’s
determination that those SIP approvals
were in error to the extent they provided
explicitly or implicitly that compliance
with CAIR satisfies the requirements of
110(a)(2)(D)(i)(I) with respect to the
1997 ozone and 1997 PM2.5 NAAQS.
The July 2008 decision of the DC Circuit
held, among other things, that the CAIR
rule did not ‘‘achieve[] something
measureable toward the goal of
prohibiting sources ‘within the State’
from contributing to nonattainment or
interfering with maintenance in ‘any
other State.’’’ North Carolina, 531 F.3d
908; see also, e.g., id. at 916 (EPA not
exercising its authority to make
measureable progress towards the goals
of section 110(a)(2)(D)(i)(I) because the
emission budgets were insufficiently
related to the statutory mandate). EPA’s
actions to approve CAIR SIP submittals
as satisfying the requirements of section
110(a)(2)(D)(i)(I), based on the flawed
determination in CAIR that compliance
with CAIR satisfied those statutory
requirements, were thus in error as were
the separate actions taken to approve
section 110(a)(2)(D)(i)(I) submissions
that relied wholly or in part on CAIR.
The approval for Alabama titled
‘‘Approval and Promulgation of
Implementation Plans; Alabama; Clean
Air Interstate Rule’’ which is hereby
corrected was originally published in
the Federal Register on October 1, 2007
(72 FR 55659).
The approval for Arkansas titled
‘‘Approval and Promulgation of
Implementation Plans; Arkansas; Clean
Air Interstate Rule Nitrogen Oxides
Ozone Season Trading Program’’ which
is hereby corrected was originally
published in the Federal Register on
September 26, 2007 (72 FR 54556).
The approval for Connecticut titled
‘‘Approval and Promulgation of Air
Quality Implementation Plans;
Connecticut; State Implementation Plan
Revision to Implement the Clean Air
Interstate Rule’’ which is hereby
corrected was originally published in
the Federal Register on January 24,
2008 (73 FR 4105) and the approval for
Connecticut titled ‘‘Approval and
Promulgation of Air Quality
Implementation Plans; Connecticut;
Interstate Transport of Pollution’’ which
is hereby corrected was originally
published in the Federal Register on
May 7, 2008 (73 FR 25516).
The approval for Florida titled
‘‘Approval and Promulgation of
Implementation Plans; Florida; Clean
Air Interstate Rule’’ which is hereby
corrected was originally published in
the Federal Register on October 12,
2007 (72 FR 58016).
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The approval for Georgia titled
‘‘Approval and Promulgation of
Implementation Plans; Georgia; Clean
Air Interstate Rule’’ which is hereby
corrected was originally published in
the Federal Register on October 9, 2007
(72 FR 57202).
The approval for Illinois titled
‘‘Approval of Implementation Plans of
Illinois: Clean Air Interstate Rule’’
which is hereby corrected was originally
published in the Federal Register on
October 16, 2007 (72 FR 58528).
The approval for Indiana titled
‘‘Limited Approval of Implementation
Plans of Indiana: Clean Air Interstate
Rule’’ which is hereby corrected was
originally published in the Federal
Register on October 22, 2007 (72 FR
59480) and the approval for Indiana
titled ‘‘Approval and Promulgation of
Air Quality Implementation Plans;
Indiana; Clean Air Interstate Rule’’
which is hereby corrected was originally
published in the Federal Register on
November 29, 2010 (75 FR 72956).
The approval for Iowa titled
‘‘Approval and Promulgation of
Implementation Plans; Iowa; Clean Air
Interstate Rule’’ which is hereby
corrected was originally published in
the Federal Register on August 6, 2007
(72 FR 43539) and the approval for Iowa
titled ‘‘Approval and Promulgation of
Implementation Plans; Iowa; Interstate
Transport of Pollution’’ which is hereby
corrected was originally published in
the Federal Register on March 8, 2007
(72 FR 10380).
The approval for Kentucky titled
‘‘Approval of Implementation Plans of
Kentucky: Clean Air Interstate Rule’’
which is hereby corrected was originally
published in the Federal Register on
October 4, 2007 (72 FR 56623).
The approval for Louisiana titled
‘‘Approval and Promulgation of
Implementation Plans; Louisiana; Clean
Air Interstate Rule Sulfur Dioxide
Trading Program’’ which is hereby
corrected was originally published in
the Federal Register on July 20, 2007
(72 FR 39741) and the approval for
Louisiana titled ‘‘Approval and
Promulgation of Implementation Plans;
Louisiana; Clean Air Interstate Rule
Nitrogen Oxides Trading Program’’
which is hereby corrected was originally
published in the Federal Register on
September 28, 2007 (72 FR 55064).
The approval for Maryland titled
‘‘Approval and Promulgation of Air
Quality Implementation Plans;
Maryland; Clean Air Interstate Rule’’
which is hereby corrected was originally
published in the Federal Register on
October 30, 2009 (74 FR 56117).
The approval for Massachusetts titled
‘‘Approval and Promulgation of Air
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Quality Implementation Plans;
Massachusetts; State Implementation
Plan Revision to Implement the Clean
Air Interstate Rule’’ which is hereby
corrected was originally published in
the Federal Register on December 3,
2007 (72 FR 67854).
The approval for Minnesota titled
‘‘Approval and Promulgation of Air
Quality Implementation Plans;
Minnesota; Interstate Transport of
Pollution’’ which is hereby corrected
was originally published in the Federal
Register on June 2, 2008 (73 FR 31366).
The approval for Mississippi titled
‘‘Approval and Promulgation of
Implementation Plans; Mississippi:
Clean Air Interstate Rule’’ which is
hereby corrected was originally
published in the Federal Register on
October 3, 2007 (72 FR 56268).
The approval for Missouri titled
‘‘Approval and Promulgation of
Implementation Plans; Missouri; Clean
Air Interstate Rule’’ which is hereby
corrected was originally published in
the Federal Register on December 14,
2007 (72 FR 71073) and the approval of
Missouri titled ‘‘Approval and
Promulgation of Implementation Plans;
Missouri; Interstate Transport of
Pollution’’ which is hereby corrected
was originally published in the Federal
Register on May 8, 2007 (75 FR 25975).
The approval for New York titled
‘‘Approval and Promulgation of
Implementation Plans; New York: Clean
Air Interstate Rule’’ which is hereby
corrected was originally published in
the Federal Register on January 24,
2008 (73 FR 4109).
The approval for North Carolina titled
‘‘Approval of Implementation Plans;
North Carolina: Clean Air Interstate
Rule’’ which is hereby corrected was
originally published in the Federal
Register on October 5, 2007 (72 FR
56914) and the approval for North
Carolina titled ‘‘Approval and
Promulgation of Air Quality
Implementation Plans; North Carolina;
Clean Air Interstate Rule’’ which is
hereby corrected was originally
published in the Federal Register on
November 30, 2009 (74 FR 62496).
The approval for Ohio titled
‘‘Approval and Promulgation of Air
Quality Implementation Plans; Ohio;
Clean Air Interstate Rule’’ which is
hereby corrected was originally
published in the Federal Register on
February 1, 2008 (73 FR 6034) and the
approval for Ohio titled ‘‘Approval and
Promulgation of Air Quality
Implementation Plans; Ohio; Clean Air
Interstate Rule’’ which is hereby
corrected was originally published in
the Federal Register on September 25,
2009 (74 FR 48857).
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The approval for Pennsylvania titled
‘‘Approval and Promulgation of Air
Quality Implementation Plans;
Pennsylvania; Clean Air Interstate Rule;
NOX SIP Call Rule; Amendments to
NOX Control Rules’’ which is hereby
corrected was originally published in
the Federal Register on December 10,
2009 (74 FR 65446).
The approval for South Carolina titled
‘‘Approval of Implementation Plans of
South Carolina: Clean Air Interstate
Rule’’ which is hereby corrected was
originally published in the Federal
Register on October 9, 2007 (72 FR
57209) and the approval for South
Carolina titled ‘‘Approval and
Promulgation of Air Quality
Implementation Plans; South Carolina;
Clean Air Interstate Rule’’ which is
hereby corrected was originally
published in the Federal Register on
October 16, 2009 (74 FR 53167).
The approval for Virginia titled
‘‘Approval and Promulgation of Air
Quality Implementation Plans; Virginia;
Clean Air Interstate Rule Budget
Trading Programs’’ which is hereby
corrected was originally published in
the Federal Register on December 28,
2007 (72 FR 73602).
The approval for West Virginia titled
‘‘Approval and Promulgation of Air
Quality Implementation Plans; West
Virginia; Clean Air Interstate Rule’’
which is hereby corrected was originally
published in the Federal Register on
December 18, 2007 (72 FR 71576) and
the approval for West Virginia titled
‘‘Approval and Promulgation of Air
Quality Implementation Plans; West
Virginia; Clean Air Interstate Rule’’
which is hereby corrected was originally
published in the Federal Register on
August 4, 2009 (74 FR 38536).
EPA is taking this final action without
prior opportunity for notice and
comment because EPA finds, for good
cause, that notice and public procedure
thereon are unnecessary and not in the
public interest. Section 553(b)(B) of the
Administrative Procedure Act provides
that the notice and comment
requirements in section 553 do not
apply when the agency for good cause
finds that notice and public procedure
there on are impracticable, unnecessary,
or contrary to the public interest. 5
U.S.C. 553(b)(B). Section 307(d)(1) of
the CAA in turn provides that the
requirements of section 307(d) do not
apply in the case of a rule or
circumstance referred to in section
553(b)(A) or section 553(b)(B) of the
Administrative Procedure Act in Title 5.
42 U.S.C. 7607(1).
EPA finds that notice and public
procedure are unnecessary because EPA
has no discretion given the specific
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circumstances presented in this case.
EPA is bound by the decisions of the
courts and must act in accordance with
those decisions. EPA must accept the
Court’s conclusion that compliance with
CAIR does not satisfy the requirements
of CAA section 110(a)(2)(D)(i)(I) and
lacks discretion to reach a different
conclusion. This correction is a
ministerial matter consistent with the
decisions of the courts. For these
reasons, it is unnecessary to provide an
opportunity for notice and comment.
V. Analysis of Downwind Air Quality
and Upwind State Emissions
A. Pollutants Regulated
To address interstate transport of air
pollution, EPA must choose which
pollutants to regulate relevant to
significant contribution to
nonattainment or interference with
maintenance of the NAAQS of concern
downwind. This section of the preamble
discusses the pollutants regulated under
the final Transport Rule.
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1. Background
Based on scientific and technical
information, as well as EPA’s air quality
modeling, EPA concluded for CAIR that
the most effective approach to reducing
the contribution of interstate transport
to PM2.5 was to control SO2 and NOX
emissions. For CAIR, EPA did not limit
emissions of other components of PM2.5,
noting that ‘‘current information relating
to sources and controls for other
components identified in transported
PM2.5 (carbonaceous particles,
ammonium, and crustal materials) does
not, at this time, provide an adequate
basis for regulating the regional
transport of emissions responsible for
these PM2.5 components’’ (69 FR 4582).
With respect to ozone transport, EPA
has previously concluded that it is
proper to control ozone-season NOX
emissions. For CAIR and the NOX SIP
Call programs, EPA based this
conclusion on the assessment of ozone
transport conducted by the Ozone
Transport Assessment Group (OTAG) in
the mid-1990s. The OTAG Regional and
Urban Scale Modeling and Air Quality
Analysis Work Groups concluded that
regional NOX emission reductions are
effective in producing ozone benefits
that grow with increasing regional NOX
abatement.
The relative importance of NOX and
VOC in ozone formation and control
varies with local and time-specific
factors, including the relative amounts
of VOC and NOX present. In rural areas
and many urban areas with high
concentrations of VOC from biogenic
sources, ozone formation and control is
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governed by NOX. In some urban core
situations, NOX concentrations can be
high enough relative to VOC to suppress
ozone formation locally, but still
contribute to increased ozone
downwind from the city. In such
situations, VOC reductions are most
effective at reducing ozone within the
urban environment and immediately
downwind. The formation of ozone
increases with temperature and
sunlight, which is one reason ozone
levels are higher during the summer.
Increased temperature also increases
emissions of volatile man-made and
biogenic organics and can indirectly
increase NOX as well (e.g., increased
electricity generation for air
conditioning). Summertime conditions
also bring increased episodes of large
scale stagnation of air masses, which
promote the build-up of direct
emissions and pollutants formed
through atmospheric reactions over
large regions. Authoritative assessments
of ozone control approaches have
concluded that, for reducing regional
scale ozone transport, a NOX control
strategy is most effective, whereas VOC
reductions are generally most effective
locally, in more dense urbanized areas.
Studies conducted since the 1970s
established that ozone occurs on a
regional scale (i.e., thousands of
kilometers) over much of the eastern
U.S., with elevated concentrations
occurring in rural as well as
metropolitan areas. While substantial
progress has been made in reducing
ozone in many urban areas, regionalscale ozone transport is still an
important component of high ozone
concentrations during the extended
summer ozone season. A series of more
recent progress reports discussing the
effect of the NOX SIP Call reductions
can be found on EPA’s Web site at:
https://www.epa.gov/airmarkets/
progress/progress-reports.html.
More recent assessments of ozone
(including those conducted for the
Regulatory Impact Analysis for the
ozone standards in 2008) continue to
show the importance of NOX transport
as a factor in ozone formation. For
addressing interstate ozone transport in
CAIR, EPA required NOX emission
reductions but did not include
requirements for VOCs. EPA believes
that VOCs from some upwind states do
indeed have an impact in some nearby
downwind states, particularly over short
transport distances. EPA expects that
states, typically in local nonattainment
planning, would benefit from examining
the extent to which VOC emissions
affect ozone pollution levels within and
near urban nonattainment areas, and
states may identify areas where multi-
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state VOC strategies might assist in
attainment planning for meeting the 8hour standard. However, EPA continues
to believe that the most effective
regional pollution control strategy for
mitigation of interstate transport of
ozone remains NOX emission
reductions.
2. Which pollutants did EPA propose to
control for purposes of PM2.5 and ozone
transport?
For the proposed rule, EPA concluded
that its findings in CAIR regarding the
nature of pollutant contributions are
still appropriate. EPA proposed to
require SO2 and annual NOX emission
reductions to control PM2.5 transport
and to require ozone-season NOX
emission reductions to control ozone
transport. In the proposal, EPA
discussed and requested comment on
the inclusion of southern states in the
annual NOX program for PM2.5 control.
3. Comments and Responses
EPA received no adverse comments
on its proposal to regulate SO2 for
addressing PM2.5 transport, the proposal
not to regulate direct PM2.5 or organic
PM2.5 precursors, and the proposal to
focus ozone-season efforts on NOX and
not to regulate VOCs.
One commenter questioned EPA’s
regulation of NOX for purposes of
addressing PM2.5 transport in all states
(including northern states with cooler
climates and higher nitrate deposition).
Several commenters, representing
southern state air quality agencies and
regulated sources in southern states,
disagreed with EPA’s proposed
regulation of annual NOX emissions for
all regulated states. These commenters,
while not disagreeing with the need for
regulation of SO2, observed that in
EPA’s modeling analysis, contributions
from certain southern states’ NOX
emissions to PM2.5 in downwind states
were relatively small.
Accordingly, these commenters
argued that either (1) EPA should
remove NOX as a precursor analyzed for
PM2.5 contribution from those states, or
(2) the required remedy for emission
reductions in those states should not
require reductions in annual NOX.
For the final rule, EPA retains the
approach for regulated pollutants in the
proposal, which regulates annual NOX
and SO2 for states affecting downwind
state PM2.5 nonattainment and
maintenance sites, and ozone-season
NOX for states impacting downwind
state ozone nonattainment and
maintenance. EPA considered
commenters’ requests to remove some
states from the annual NOX program.
However, EPA believes that it is
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appropriate to establish a cap on these
states’ annual NOX emissions, in part to
ensure the continued annual operation
of existing control equipment that
would prevent substantial increases in
NOX emissions. EPA believes that
without these reductions, increased
‘‘nitrate replacement’’ could occur, a
known atmospheric phenomenon
whereby some of the sulfate reductions
due to SO2 emission reductions are
eroded by increases in nitrate
concentrations due solely to those SO2
reductions.16 This is an especially
pertinent concern for southern states
which have significant impacts on
northern receptors in colder climates
where nitrate concentrations are
generally higher. For example, Alabama
and Tennessee are both linked to
Washtenaw County, MI for 24-hour
PM2.5; North Carolina is linked to
Lancaster County, PA for 24-hour PM2.5;
and Texas is linked to Madison County,
IL for both annual and 24-hour PM2.5.
All of these downwind areas have
appreciable nitrate deposition
contributing to nonattainment and
maintenance concerns for the PM2.5
NAAQS. If the states linked to those
receptors were to make SO2 reductions
only, their beneficial impact on
downwind air quality would be
partially eroded by nitrate replacement.
EPA therefore believes that it is
reasonable to seek both SO2 and NOX
reductions from states included in the
Transport Rule program that are found
to significantly contribute to
nonattainment or interfere with
maintenance of the PM2.5 NAAQS in
downwind states.
In addition, EPA notes that there
would be important disbenefits to
effectively removing CAIR’s existing
annual NOX requirements in those
states. If EPA were to allow annual NOX
emissions to increase for those states,
there would be potentially harmful
effects on visibility, nitrogen deposition,
and other aspects of human and
environmental health.
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B. Baseline for Pollution Transport
Analysis
Implementing the mandate of CAA
section 110(a)(2)(D)(i)(I) requires EPA to
determine which states significantly
contribute to nonattainment and
interfere with maintenance of the
NAAQS in other states, as well as to
16 SO reductions successfully decrease
2
atmospheric formation of ammonium sulfate, but in
doing so they ‘‘free up’’ the ammonia component
that would otherwise have reacted with SO2 and is
now free to react with NOX instead, causing a
‘‘rebound effect’’ partially eroding the improvement
in PM2.5 concentrations. This effect can be mitigated
with tandem NOX reductions.
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quantify the emissions in each state that
must be eliminated. This process begins
with an analysis of baseline emissions.
Baseline emissions are the emissions
that would occur in each state if EPA
did not promulgate the Transport Rule.
To conduct such analysis, EPA
generally takes into account emission
limitations that are currently, and will
continue to be, in place. From that
baseline, EPA analyzes whether
additional reductions are necessary
beyond those already mandated by
existing emission limitation
requirements. For example, the base
case used in CAIR reflected the
reductions already required by the NOX
SIP Call, which remained in effect even
after the CAIR emission reduction
requirements took effect.
The unique legal situation addressed
by the Transport Rule necessarily affects
the quantification of baseline emissions.
Specifically, because the Transport Rule
will replace CAIR, EPA cannot consider
reductions associated with CAIR in the
‘‘base case’’ (i.e., analytical baseline
emissions scenario). If EPA were to
consider all reductions associated with
CAIR in the ‘‘base case,’’ the baseline
emissions would not adequately reflect
the true 2012 baseline in each state (i.e.,
the emissions that would occur in each
state in 2012 if the Transport Rule did
not require any reductions in that state).
Similarly, if EPA were to treat the
capital investments that have already
been made to meet the requirements of
CAIR as new costs rather than treating
them as ‘‘sunk’’ capital costs, EPA’s
analysis would not accurately reflect the
cost of emission reductions required by
the Transport Rule. As explained below,
EPA’s analysis both properly considered
all capital investments made in
response to CAIR and properly
recognized that, after CAIR is
terminated, the emission limitations
imposed by CAIR will cease to exist.
In 2005 EPA promulgated CAIR,
which required large electric generating
units in 29 states to make phase I
emission reductions in NOX emissions
starting in 2009, phase I emission
reductions in SO2 starting in 2010 and
phase II reductions in emissions of both
pollutants starting in 2015. On July 11,
2008, the DC Court of Appeals held that
CAIR had ‘‘more than several fatal
flaws,’’ North Carolina, 531 F.3d at 901,
and remanded and vacated the rule, id.
at 930. The Court subsequently granted
EPA’s petition for rehearing in part and
remanded CAIR without vacatur ‘‘for
EPA to conduct further proceedings
consistent with’’ the Court’s July 11,
2008 opinion. North Carolina, 550 F.3d
1176. The Court explained that it was
‘‘allowing CAIR to remain in effect until
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it is replaced by a rule consistent with
[the July 11, 2008] opinion’’ because
this ‘‘would at least temporarily
preserve the environmental values
covered by CAIR.’’ Id. at 1178.
Moreover, the Court stated that it did
not ‘‘intend to grant an indefinite stay
of the effectiveness of’’ the July 11, 2008
order vacating CAIR. Id. In summary,
the Court determined that CAIR was
fatally flawed and could remain in effect
only as a stopgap measure until EPA
could act to replace it.
Thus, unlike most other regulatory
requirements (such as the Acid Rain
Program under CAA Title IV, the NOX
Budget Trading Program under the NOX
SIP Call, New Source Performance
Standards, and state laws and consent
orders requiring emission reductions),
the emission limitations contained in
CAIR are only temporary. Moreover, the
duration of these limitations is directly
tied to the Transport Rule. The
Transport Rule replaces CAIR. Thus,
CAIR itself will be terminated for the
SO2, annual NOX, and ozone-season
NOX control periods starting in 2012
when the emission limitations
established in the final Transport Rule
for those control periods take effect
(January 1, 2012 for the annual control
periods and May 1, 2012 for the ozoneseason control period). For this reason,
emission reductions made to comply
with CAIR cannot be treated as if they
were emission reductions achieved to
comply with statutory provisions, rules,
consent decrees, and other enforceable
requirements that establish permanent
emission limitations. EPA takes
reductions made to comply with
permanent limitations into
consideration when quantifying each
state’s baseline emissions for the
purpose of analyzing whether its
emissions significantly contribute to
nonattainment or interfere with
maintenance in another state. However,
the unique legal status of CAIR and its
replacement with the Transport Rule
distinguish the emission reductions
required by CAIR from those of other
regulatory requirements. Since the
limitations and emission reduction
requirements in CAIR are temporary and
will be terminated by the Transport
Rule, they must be excluded from the
Transport Rule’s base case analysis.
Some comments on the Transport
Rule proposal claim that EPA’s
treatment of CAIR is inconsistent with
the treatment, in prior rulemakings, of
the Acid Rain Program and the NOX SIP
Call. Such comments ignore the unique
legal status of CAIR, and EPA therefore
rejects these claims.
A simple example illustrates this
point. Assume state Z’s emissions before
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CAIR were 2,000 tons and that state Z
was required by CAIR to reduce its
emissions to 1,000 tons. If EPA were to
determine that state Z’s baseline
emissions were 1,000 tons and then
conclude, based on that assumption,
that no additional reductions in state Z
are necessary because state Z does not
significantly contribute to downwind
nonattainment unless its emissions
exceed 1,500 tons, then state Z would
not be covered by the Transport Rule.
However, the Transport Rule will
terminate all CAIR requirements in all
CAIR states regardless of whether they
are covered by the Transport Rule.
Thus, after promulgation of the
Transport Rule, state Z would again be
allowed, and would be projected in this
example, to emit 2,000 tons. In other
words, state Z would be allowed to
significantly contribute to
nonattainment and/or interfere with
maintenance in other states—a result
that would be inconsistent with the
statutory mandate of CAA section
110(a)(2)(D)(i)(I). On the other hand, if
EPA assumes state Z’s baseline
emissions are 2,000 tons as projected
without CAIR in place, EPA can
properly determine whether, if state Z
were allowed to emit that amount (i.e.,
the amount state Z would be projected
to emit if excluded from the Transport
Rule), the state would significantly
contribute to nonattainment or interfere
with maintenance in any other state. In
other words, EPA can determine the
stringency of emission limitations
needed (if any) to replace those that
were established by CAIR in order to
ensure that state Z prohibits all
emissions that significantly contribute
to nonattainment or interfere with
maintenance in other states.
In fact, commenters’ suggestion that
the Transport Rule base case should
include CAIR would cause the
anomalous result of excluding sources
in a state from the Transport Rule
because of their CAIR–required
emission reductions while
simultaneously eliminating those CAIR
emission reduction requirements. If
EPA’s base case analysis were to assume
erroneously that reductions from CAIR
would continue indefinitely, a state
currently covered by CAIR, but not
covered by the Transport Rule, would
have no CAIR requirements once the
Transport Rule programs began and so
could increase emissions beyond the
CAIR limitations. Downwind areas that
are in attainment (and are not
experiencing interference with
maintenance of such attainment) solely
because of emission reductions required
by CAIR could again face nonattainment
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or interference with maintenance
problems because the current protection
from upwind pollution from such an
upwind state would not be replaced. In
short, the analysis of whether a state
should be included in a rule eliminating
and replacing CAIR cannot logically
assume that CAIR remains in place. For
these reasons, EPA believes it is
reasonable to use a base case that does
not assume that the CAIR reduction
requirements will continue to be
achieved and so does not include CAIRspecific emission reductions.
As a result, EPA’s 2012 base case
shows emissions higher than current
levels in some states. In the absence of
the CAIR SO2 and NOX programs that
EPA has been directed to eliminate and
replace, utility emissions in CAIR states
will be limited only by non-CAIR
constraints including the Acid Rain
Program, the NOX SIP Call, New Source
Performance Standards, any state laws
and consent order requiring emission
reductions, and any other permanent
and enforceable binding reduction
commitments. This will lead to
increased emissions in some states in
the 2012 base case relative to current
emissions. For example, efforts to
comply with the Acid Rain Program at
the least cost may occur, in some cases,
without the operation of existing
scrubbers through use of readily
available, inexpensive Title IV
allowances.
It is important to note that, to the
extent that emission reductions
currently required by CAIR are also
reflected in emission reduction
requirements under the Acid Rain
Program, the NOX SIP Call, New Source
Performance Standards, any state laws
and consent orders requiring emission
reductions, and any other enforceable
binding reduction commitments, such
reductions are accounted for in EPA’s
2012 base case. Some commenter
claimed that in excluding CAIR-specific
emission reductions from the base case,
EPA ignores non-CAIR legal
requirements (e.g., in Title V permits)
that may prevent sources from
increasing emissions above CAIR levels.
Such allegations are incorrect. As
discussed elsewhere in this preamble,
EPA accounted for any Title V permits,
consent decrees, state rules, and other
enforceable limitations on sources’
emissions; if these non-CAIR limitations
effectively restrain a state’s emissions to
not exceed the state’s CAIR limitations,
EPA’s base case modeling would reflect
this outcome. Commenters also assert
that utilities are unlikely to dismantle or
discontinue running the installed
controls to the point of returning to preCAIR emission levels. EPA agrees that
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installed controls are not likely to be
physically dismantled, and as discussed
elsewhere in this preamble, EPA’s
analysis properly treats the capital
investments made in emission controls
attributed to CAIR as ‘‘sunk’’ capital
costs (i.e., capital costs already obligated
in the past) that are not included as
costs of meeting Transport Rule
requirements.
Our cost analysis for significant
contribution reflects on-the-ground
realities. Investments in pollution
control equipment were made in
response to CAIR requirements. Those
expenditures are ‘‘sunk’’ capital costs,
meaning that those investments were
committed in the past, prior to the
Transport Rule. Adding the capital costs
of that equipment into the costs of
Transport Rule emission reduction
options would be incorrect; those
capital investments are represented in
place in the base case.
However, given ongoing costs
associated with operating these controls,
EPA believes sources would have an
economic incentive to discontinue
operating installed controls, or to
operate those controls less effectively,
except to the extent non-CAIR legal
requirements mandate emission
reductions or to the extent that sources
would find it economic to operate the
controls for non-CAIR market-based
emission control programs. EPA
properly treats the costs of operating
controls installed to meet CAIR
requirements as costs of meeting
Transport Rule requirements.17 EPA’s
base case accounts for non-CAIR
requirements and does not make the
unreasonable assumption that installed
controls would be operated to achieve
emission reductions that are not
necessary to meet non-CAIR
requirements. For all of these reasons,
EPA rejects commenters’ claims that the
base case is ‘‘unrepresentative’’ or lacks
‘‘a rational relationship to the real
world.’’
C. Air Quality Modeling To Identify
Downwind Nonattainment and
Maintenance Receptors
1. Emission Inventories
To inform air quality modeling for the
development of the final Transport
Rule, EPA developed emission
17 For more details on how EPA models economic
operation of existing pollution control equipment in
the Transport Rule base case, please see Section 6
(‘‘Dispatchable Controls’’) in ‘‘Updates to EPA Base
Case v3.02 EISA Using the Integrated Planning
Model’’ Technical Support Document (TSD) for the
Transport Rule Docket ID No. EPA–HQ–OAR–
2009–0491, U.S. EPA, July 2010 (available at https://
www.epa.gov/airmarkets/progsregs/epa-ipm/IPM
Update Documentation.pdf).
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inventories for a 2005 base year and for
2012 and 2014 projections. The
inventories for all years include
emission estimates for EGUs, non-EGU
point sources, stationary nonpoint
sources, onroad mobile sources,
nonroad mobile sources, and biogenic
(non-human) sources. EPA’s air quality
modeling relies on this comprehensive
set of emission inventories because
emissions from multiple source
categories are needed to model ambient
air quality and to facilitate comparison
of model outputs with ambient
measurements. In addition, EPA
considers all relevant emissions
(regardless of source category) when
determining whether a state is found to
be significantly contributing to or
interfering with maintenance of a
particular NAAQS in another state.
The emission inventories were
processed through the Sparse Matrix
Operator Kernel Emissions (SMOKE)
Modeling System version 2.6 to produce
the gridded, hourly, speciated, modelready emissions for input to the CAMx
air quality model. Additional
information on the development of the
emission inventories and related data
sets for emissions modeling are
provided in the Emission Inventory
Final Transport Rule TSD.
On October 27, 2010, EPA issued a
NODA on ‘‘Revisions to Emission
Inventories.’’ The NODA’s primary
purpose was to notify the public about
changes to emission inventories made
since the proposal modeling. The
affected emission sectors were non-EGU
stationary point sources, nonpoint
sources, and Category 3 commercial
marine vessel sources. The NODA also
presented a newly released model for
developing onroad mobile source
emissions for use in air quality
modeling for the final Transport Rule.
The major comments received in
response to the emission inventories
and modeling included in the proposed
Transport Rule and the October 27
NODA are summarized in the following
subsections. EPA agreed with the
comments summarized below and
adopted technical corrections or
updates to the emission inventories and
modeling accordingly. For EPA to be
able to take appropriate action,
comments on the emission inventories
needed to be specific enough to allow
for credible alternative data sources to
be located. EPA adopted corrections
from comments on in-place control
programs or devices where the controls
were enforceable and quantifiable.
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a. Foundation Emission Inventory Data
Sets
EPA developed emission data
representing the year 2005 to support air
quality modeling of a base year from
which future air quality could be
forecasted. EPA used the 2005 National
Emission Inventory (NEI), version 2
from October 6, 2008, as the chief basis
for the U.S. inventories supporting the
2005 air quality modeling. This
inventory includes 2005-specific data
for point and mobile sources, while
most nonpoint data were carried
forward from version 3 of the 2002 NEI.
The future base case scenarios modeled
for 2012 and 2014 represent predicted
emission reductions primarily from
already promulgated federal measures.
EPA used a 2006 Canadian inventory
and a 1999 Mexican inventory for the
portions of Canada and Mexico within
the air quality modeling domains for all
modeled scenarios. Emissions from
Canada and Mexico for all source
sectors (including EGUs) in these
countries were held constant for all
base- and future-year cases. EPA made
this assumption because it does not
currently have sufficient data to support
projections of future-year emissions
from Canada and Mexico.
b. Development of Emission Inventories
for EGUs
The annual NOX and SO2 emissions
for EGUs in the 2005 NEI v2 are based
primarily on data from continuous
emissions monitoring systems (CEMS),
with other EGU pollutants estimated
using emission factors and annual heat
input data reported to EPA. Although
only NOX and SO2 are considered for
control in this rule, emissions for all
criteria air pollutants are necessary to
model air quality. For EGUs without
CEMS, EPA used data submitted to the
NEI by the states. For more information
on the details of how the 2005 EGU
emissions were developed, see the
Emissions Inventory Final Rule TSD.
Commenters stated that some point
sources that were classified as nonEGUs in the proposal modeling were
actually EGUs, resulting in double
counting of emissions in future-year
modeling. EPA reviewed its assignment
of EGUs and non-EGUs and reclassified
EGU sources found to be in the nonEGU inventory for the updated 2005
EGU inventory to prevent double
counting of future-year emissions.
The future base case scenarios for
EGUs reflect projected changes to fuel
usage and economics, as described in
the Emission Inventory Final Rule TSD.
Future year base case EGU emissions
that predict SO2, NOX, and PM2.5 were
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obtained from version 4.10_FTransport
of the Integrated Planning Model (IPM)
outputs (https://www.epa.gov/airmarkt/
progsregs/epa-ipm/). The
IPM is a multi-regional, dynamic,
deterministic linear programming model
of the U.S. electric power sector; version
4.10_FTransport reflects state rules and
consent decrees through December 1,
2010, and incorporates public
comments on existing controls
submitted to EPA through both the
Transport Rule-related notice and
comment process as well as the
proposed Mercury and Air Toxics
Standards Information Collection
Request (ICR). The operation of existing
SO2 or NOX advanced controls (e.g.,
scrubber, SCR) on units that were not
required to operate those controls for
compliance with Title IV, New Source
Review (NSR), state settlements, or
state-specific rules was projected by
IPM on the basis of providing least cost
operation of the power generation
system subject to existing regulatory
requirements except CAIR (see baseline
discussion in section V.B).
Additionally, IPM v.4.10_FTransport
incorporates comments received during
the rulemaking process. Fuel-related
updates include comment-driven unitspecific limitations on 2012 coal rank
selection, limiting unrestricted
switching from bituminous to
subbituminous coal by imposing boiler
modification costs for those units
shifting from bituminous to
subbituminous coal without historical
precedent, and a correction of waste
coal prices. Pollution control-related
updates include keying the performance
assumptions for FGD and SCR more
closely to historic performance data,
and the inclusion of dry sorbent
injection (DSI), a SO2 removal
technology. Other notable updates
include revised assumptions on the heat
rate and consequent dispatching of
cogenerating units and incorporation of
additional planned retirements. Further
details on these updates are available in
the IPM Documentation, available in the
docket and at: https://www.epa.gov/
airmarkets/progsregs/epa-ipm/
index.html.
c. Development of Emission Inventories
for Non-EGU Point Sources
Details on the development of
emission inventories are available in the
Emission Inventory Final Rule TSD. In
both the proposal and final modeling,
controls on industrial boilers installed
under the NOX SIP call were assumed
to have been implemented by 2005 and
captured in the 2005 NEI v2. The nonEGU point source emissions were
updated from the 2005 NEI and the
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emissions used for the proposal
modeling through the incorporation of
comments on the proposal emissions
values, previously unknown facility
closures, and through other data
improvements as identified by EPA
analyses.
EPA does not factor in economic
growth to develop non-EGU point
source emission projections because
analysis of historical emission trends
and economic data did not support
using economic growth to project nonEGU emissions. More details on the
rationale for not applying economic
growth to non-EGU industrial sources
can be found in Appendix D of the
Regulatory Impact Assessment (RIA) for
the PM NAAQS rule (https://
www.epa.gov/ttn/ecas/regdata/RIAs/
Appendix%20D—Inventory.pdf).
Although projections based on
economic growth were not included,
EPA did include reductions resulting
from plant and unit closures, local and
federal consent decrees, and several
Maximum Achievable Control
Technology (MACT) standards.
For non-EGU point sources, local
control programs that may be necessary
for areas to attain the annual PM2.5
NAAQS and the ozone NAAQS are only
included in the future base case
projections when specific information
about existing enforceable local controls
was provided.
Since aircraft at airports were treated
as point emissions sources in the 2005
NEI v2, we applied projection factors
based on activity growth projected by
the Federal Aviation Administration
Terminal Area Forecast (TAF) system,
published in December 2008.
A number of comments were received
on the stationary non-EGU point source
inventories. Below is a summary of the
major comments that impacted the
stationary non-EGU point source
inventories for the final modeling:
Comment: Commenters stated that
EPA did not properly represent some
point source emissions in base-year and
future-year inventories due to facility
and unit closures, consent decrees,
emission caps, control programs, and
alternative emission estimates.
Response: EPA reviewed the sources
referenced in the individual comments
regarding the base-year and future-year
inventories. In cases where credible
alternative data were available, EPA
revised the emission inventories to
incorporate additional facility and unit
closures, consent decrees, emission
caps, control programs, enforceable
local controls, and alternative emission
estimates.
Comment: Commenters stated that
EPA should include controls from the
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National Emission Standards for
Hazardous Air Pollutants for
Reciprocating Internal Combustion
Engines (RICE NESHAP) in our
modeling.
Response: EPA included reductions
expected to be achieved by the RICE
NESHAP across the United States in our
final modeling of stationary non-EGU
and nonpoint sources.
Comment: Commenters stated that
EPA was not properly representing
existing or planned controls for cement
plants.
Response: EPA updated control and
projection information for cement plants
based on the latest available data and
cement sector-specific modeling results.
Comment: EPA specifically requested
comments on whether to incorporate
emission reduction estimates from the
NESHAP for Major Sources: Industrial,
Commercial, and Institutional Boilers
and Process Heaters (75 FR 32006).
Commenters stated that emission
reduction estimates should not be
included until the rule became final.
Response: EPA did not incorporate
emission reduction estimates from the
NESHAP for Major Sources: Industrial,
Commercial, and Institutional Boilers
and Process Heaters (75 FR 32006) into
the proposal or final modeling because
the rule was not final at the time the
modeling was performed. Note that
reductions from this rule would not
have impacted the 2012 base case due
to its implementation schedule, and
only the 2014 emissions would have
been affected.
d. Development of Emission Inventories
for Onroad Mobile Sources
The onroad emissions in the proposal
modeling were primarily based on the
National Mobile Inventory Model
(NMIM) monthly, county, and process
level emissions along with gasoline
exhaust emissions from a fall 2008 draft
version of the Motor Vehicle Emission
Simulator (MOVES). A major comment
on the proposal modeling for onroad
mobile sources was the following:
Comment: Commenters stated that
EPA should use a publicly released
version of MOVES for its final
modeling.
Response: EPA updated the final
modeling to use data from the publicly
released version of the MOVES 2010
model because the model became
available in time for inclusion of its
results in the final modeling. It was not
used for the proposal modeling because
it was not available at the time the
modeling was performed.
In the final Transport Rule modeling,
EPA used MOVES 2010 state-month
level emissions for all criteria pollutants
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and all modes (evaporative, exhaust,
brake wear and tire wear) and allocated
those emissions to counties according to
state-county NMIM emissions ratios. For
California (the emissions for which are
included to support the coarse modeling
domain), the onroad mobile emissions
data were derived from data provided
by the state. These data were augmented
with MOVES 2010 outputs for NH3
because data for that pollutant had not
been provided. Additional information
on the approach to onroad mobile
source emissions is available in the
Emission Inventory Final Rule TSD.
In the future-year base modeling for
mobile sources, all national measures
available at the time of modeling were
included. The future scenarios for
mobile sources reflect projected changes
to fuel usage, as described in the
Emission Inventory Final Rule TSD.
Emissions for these years reflect onroad
mobile control programs including the
Light-Duty Vehicle Tier 2 Rule, the
Onroad Heavy-Duty Rule, the LightDuty Vehicle Greenhouse Gas Rule, the
Renewable Fuel Standards Rule, and the
Mobile Source Air Toxics (MSAT) final
rule.
e. Development of Commercial Marine
Category 3 Vessel Emission Inventories
For the 2005 modeling, the
commercial marine category 3 (C3)
vessel emissions, a portion of nonroad
mobile emissions, were augmented with
gridded 2005 emissions from the
previous modeling efforts for the rule
called ‘‘Control of Emissions from New
Marine Compression-Ignition Engines at
or Above 30 Liters per Cylinder.’’
Emissions out to 200 nautical miles
from the coastline were allocated to
states in the proposal modeling. A major
comment on the proposal modeling was
the following:
Comment: Commenters stated that
emissions from commercial marine
sources (a component of the nonroad
emissions in the summaries that were
provided for the NPR) were too high.
Response: EPA reviewed the approach
used for commercial marine C3
emissions in the proposal. In the final
modeling, instead of using the boundary
of 200 nautical miles from the coast as
was used in the proposal, EPA adopted
the Mineral Management Service statefederal water boundaries that assign
state waters 3–10 nautical miles from
the coast. This approach is consistent
with the approach used in the 2005 and
2008 National Emission Inventories. In
addition, the category 3 commercial
marine emissions were adjusted to
reflect a coordination between the
Emissions Control Area proposal to the
International Maritime Organization
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(EPA–420–F–10–041, August 2010)
control strategy; reductions of NOX,
VOC, and CO emissions for new C3
engines starting in 2011; and fuel sulfur
limits that go into effect as early as
2010.
f. Development of Emission Inventories
for Other Nonroad Mobile Sources
The nonroad mobile source emissions
for sources other than C3 marine were
primarily based on NMIM monthly,
county, and process level emissions
from the 2005 NEI v2. These emissions
were unchanged from proposal
modeling, except for PM emissions in
California that were updated to correct
for missing emissions in a few counties
and source categories.
Nonroad mobile emissions were
created for future years with NMIM
using an approach consistent with that
used for 2005. The nonroad emissions
for 2012 and 2014 were calculated using
NMIM future-year equipment
population estimates and control
programs. Nonroad mobile emission
reductions for 2012 and 2014 include
reductions to locomotives, various
nonroad engines including diesel
engines and various marine engine
types, fuel sulfur content, and
evaporative emissions standards. A
more comprehensive list of control
programs included for mobile sources is
available in the Emission Inventory
Final Rule TSD.
The 2012 and 2014 nonroad mobile
emissions for locomotives and category
1 and 2 (C1 and C2) commercial marine
vessels were based on emissions
published in EPA’s Locomotive Marine
Rule, Regulatory Impact Assessment,
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g. Development of Nonpoint Emission
Inventories
For the proposal Transport Rule
modeling, EPA augmented the 2002 NEI
nonpoint emission inventory with a
non-California Western Regional Air
Partnership (WRAP) oil and gas
exploration inventory, which includes
emissions in several states within the
eastern U.S. 12 km modeling domain
and additional states within the national
36 km modeling domain. For the final
Transport Rule modeling, EPA updated
the nonpoint emission estimates for oil
and gas sources. EPA continued to use
the same WRAP inventory from the
proposal, emissions in Texas and
Oklahoma were updated but for the
final modeling with data from the Texas
Commission on Environmental Quality
(TCEQ) and the Oklahoma Department
of Environmental Quality (DEQ),
respectively.
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The average-year county-based
inventories for wildfire and prescribed
burning emissions were unchanged
between the proposal and final
modeling.
For stationary nonpoint sources, local
control programs that may be necessary
for areas to attain the annual PM2.5
NAAQS and the ozone NAAQS are not
included in the future base case
projections unless specific information
about existing enforceable controls was
available (e.g., ozone SIP controls from
Ozone Transport Commission rules that
impact source categories such as
Consumer Products, Solvent Cleaning,
Adhesives and Sealants). EPA
specifically requested comment on local
control data as part of the proposal and
the October 27 NODA, and incorporated
any usable data that was provided into
the final inventories.
For stationary nonpoint sources,
refueling emissions were projected
using the refueling results from the
NMIM runs performed for the onroad
mobile sector.
Portable fuel container emissions
were projected to future years using
estimates from previous OTAQ
rulemaking inventories. Emissions of
ammonia and dust from animal
operations were projected based on
animal population data from the
Department of Agriculture and EPA.
Residential wood combustion was
projected by replacement of obsolete
wood stoves with new wood stoves and
a 1 percent annual increase in
fireplaces. Landfill emissions were
projected using MACT controls. All
other nonpoint sources were held
constant between 2005 and the future
years.
Some specific adjustments to the
inventories were made in the final
modeling to address comments that
were received as described below. Area
source MACT programs and controls
from the RICE NESHAP were included
in the final modeling to address
submitted comments, as were fuel sulfur
controls that were enforceable and that
take effect by 2014.
The major comments that impacted
the nonpoint sectors are as follows:
Comment: Commenters stated that the
SO2 emissions from industrial fuel
combustion in Nebraska EPA are too
high.
Response: EPA reviewed the NEI
2002-based data that had been used for
the proposal modeling and determined
that emissions from the 2005 inventory
compiled for the Central Regional Air
Planning Association (CENRAP) were
more up to date for this source category
and based on more localized data
sources. The 2005 CENRAP emissions
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for industrial fuel combustion were
used in the final modeling.
Comment: Commenters stated that
EPA should include sulfur rule controls
that take effect prior to the future years
that were modeled.
Response: EPA included quantifiable
sulfur rule controls in 2014 modeling
for those states that had implemented
the rules (New Jersey and Maine).
Comment: A commenter stated that
emissions for Delaware were
overestimated for several nonpoint
categories in base-year and future-year
inventories and provided alternative
estimates for these categories.
Response: EPA reviewed the
alternative estimates provided and
found them to be credible and based on
more detailed local scale information
than were available in the national
inventories. EPA incorporated the
alternative emission estimates for
Delaware into the final modeling.
Comment: A commenter stated that
residual oil is not used as an industrial
fuel in South Carolina.
Response: EPA analyzed the
emissions from residual oil industrial
fuel combustion in South Carolina and
all other states, and analyzed
preliminary regional planning office
inventories and the 2008 NEI
submittals. The South Carolina residual
oil industrial fuel emissions were
determined to be anomalously large in
comparison to the near zero emissions
in other submittals and were therefore
removed from the nonpoint inventory.
2. Air Quality Basis for Identifying
Receptors
a. Introduction
In this section, we describe the final
approach to identify downwind
nonattainment and maintenance
receptors. We briefly summarize the
modeling platform, the proposed
approach to identify receptors,
comments received, and the results of
the final analysis.
In the Transport Rule, EPA has
explicitly given independent meaning to
the ‘‘interfere with maintenance’’ prong
of section 110(a)(2)(D)(i)(I) by evaluating
contributions to identified maintenance
receptors as well as contributions to
identified nonattainment receptors. EPA
identified maintenance receptors as
those receptors that would have
difficulty maintaining the relevant
NAAQS in a scenario that takes into
account historic variability in air quality
at that receptor. Specifically, EPA
projects future air quality design values
based on measured data during the
period 2003 to 2007. In determining the
downwind receptors of concern, EPA
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does not solely rely on the projection of
an average design value based on
measured data from the relevant period
(in this case 2003 to 2007) to make a
determination of ‘‘attainment’’ or
‘‘nonattainment.’’ Instead, EPA also
evaluates the maximum future design
value at that receptor based on
measured data over the relevant period.
Receptors for which this latter analysis
projects design values higher than the
NAAQS are identified as maintenance
receptors.
EPA believes it is appropriate and
reasonable to use this approach to
identify receptors that may have
maintenance problems in the future.
This approach uses measured data in
order to establish potential air quality
outcomes at each receptor that take into
account the variable meteorological
conditions present across the entire
period of measured data (2003 to 2007).
EPA interprets the maximum future
design value to be a potential future air
quality outcome consistent with the
meteorology that yielded maximum
measured concentrations in the ambient
data set analyzed for that receptor. In
other words, the average design value
gives a reasonable projection of future
air quality at the receptor under
‘‘average’’ conditions. However, EPA
also recognizes that previously
experienced meteorological conditions
(e.g., dominant wind direction,
temperatures, air mass patterns)
promoting ozone or fine particle
formation that led to maximum
concentrations in the measured data
may reoccur in the future. The
maximum design value gives a
reasonable projection of future air
quality at the receptor under a scenario
in which such conditions do, in fact,
reoccur. It also identifies upwind
emissions that under those
circumstances could interfere with the
downwind area’s ability to maintain the
NAAQS.
Per the court’s opinion in North
Carolina, it is necessary for the Agency
to evaluate ‘‘interference with
maintenance’’ separately from
‘‘significant contribution to
nonattainment’’ in order to give
independent meaning to that phrase in
the statute. The approach described
above does so and provides a reasonable
basis for identifying upwind emissions
that interfere with maintenance of the
NAAQS at downwind receptors.
Because the methodology is based on
actual variations in design values
measured at the receptors, EPA believes
that the application of this design value
methodology for identifying
maintenance receptors reasonably
anticipates possible future air quality
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outcomes based on meteorological
conditions independent of emission
reduction requirements occurring
between 2005 (the base year for air
quality analysis) and 2012 (the future
year for air quality analysis of the base
case without CAIR or the Transport Rule
in place). EPA uses air quality modeling
to properly account for changes in air
quality from 2005 to 2012 due to
emission control requirements and
trends in emission source fleet turnover
(such as increasingly cleaner motor
vehicle fleets). The air quality modeling
process allows EPA to effectively adjust
measured data to project design values
in 2012 based on the forecast changes in
emissions. For a given receptor, the
forecast change in emissions from 2005
to 2012 is a constant factor applied
across all of the design values from the
period 2003 to 2007. Thus, a
comparison of the projected (futureyear) design values themselves is
equivalent to comparing the base period
design values from the data set to
consider how pollution concentrations
are affected by non-modeled factors
such as environmental and
meteorological variability independent
of the forecast emission reductions that
stem from successful imposition of
emission limitations and controls on
various sources between the base and
future modeling years. EPA believes it is
reasonable to anticipate that these yearto-year meteorological fluctuations may
reoccur at any time in the future and are
relevant to determining receptors that
are at risk of having a problem in the
future with maintenance of the NAAQS.
Therefore, EPA assesses the relationship
of the maximum projected design value
for 2012 at each receptor to the relevant
NAAQS, and where such a value
exceeds the NAAQS, EPA determines
that receptor to be a ‘‘maintenance’’
receptor for purposes of defining
interference with maintenance under
the Transport Rule.
To provide an illustrative example,
consider a hypothetical receptor ‘‘Y’’
whose measured data for 2003–2007
yields three design values for annual
fine particles: 17 for 2003–05; 14 for
2004–06; and 12 μg/m3 for 2005–07.
Thus, the maximum measured design
value for this period is 17 and the
average design value is 14.3. To
determine whether the receptor is a
nonattainment or maintenance receptor,
EPA projects a corresponding futureyear (2012) design value for each
measured design value. These
projections are based on the results of
air quality modeling, which
demonstrates predicted changes in
pollution concentrations for each
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receptor from 2005 to 2012. For this
example, assume that the projected
future-year design values that
correspond with the measured design
values, are 16 (corresponds with the
2003–05 design value of 17), 13
(corresponds with the 2004–06 design
value of 14), and 11 μg/m3 (corresponds
with the 2005–07 design value of 12).
The average future-year design value is
13.3 (corresponds with the average
measured design value from 2003–2007
of 14.3). The projected future design
values are all lower than the measured
design values because air quality is
projected to improve between 2005 and
2012. In this example, the analysis
establishes that the average projected
future design value is 13.3 and the
maximum projected future design value
is 16.
The average future (2012) projected
design value of 13.3 based on the
average design value for the period
2003–07 does not exceed the 1997
annual PM2.5 NAAQS. For this reason,
EPA would conclude that receptor Y
will most likely have attainment air
quality in the future year. Therefore, it
would not be identified as a
nonattainment receptor.
However, the future projected design
value of 16 based on the maximum
design value for the period 2003–07
does exceed the NAAQS. For this
reason, EPA would conclude that the
receptor may have difficulty
maintaining attainment with the
NAAQS under future potential
meteorological conditions. EPA
therefore would identify the receptor as
a maintenance receptor and evaluate
whether upwind state emissions
interfere with maintenance of the
NAAQS at that receptor.
EPA’s methodology accounts for the
range of meteorological conditions
reflected by design values from the
measured 2003–2007 data at receptor Y
and also accounts for the projected
changes in emissions from 2005 to 2012
at receptor Y. The range of
meteorological conditions is accounted
for by using data from three different
3-year periods as described above. The
projected changes in emissions are
accounted for by applying to the
measured design values the forecasted
change in PM2.5 concentrations, as
determined through air quality
modeling of the 2005 and 2012
emissions. In this example, the
maximum measured design value for
receptor Y is 17. This design value
represents measured data from 2003 to
2005. EPA applies to this design value
the modeled 2005–to–2012 change in
concentrations at receptor Y to obtain a
2012 maximum design value for that
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receptor, which is 16. In this way, this
maximum 2012 design value takes into
consideration the air quality impacts of
all known and legally applicable
emission limitations taking effect after
the 2003 to 2005 base period. Therefore,
each of the projected future-year design
values provide a fair representation of
future air quality at receptor Y under
different conditions while accounting
for the emissions projected to remain in
2012. EPA thus believes that if one of
these future-year design values for a
particular receptor exceeds the NAAQS,
it is reasonable to conclude that the area
may have difficulty maintaining that
NAAQS. For this reason, EPA identifies
such receptors as maintenance
receptors. In this example, EPA would
find that while receptor Y’s average
future-year design value would not
exceed the NAAQS, its maximum
future-year design value (16) would
exceed the NAAQS, and it would thus
be designated as a ‘‘maintenance’’
receptor for purposes of the Transport
Rule analyses.
In the proposed rule we used air
quality modeling to (1) Identify
locations where we expected there to be
nonattainment and/or maintenance
problems for annual average PM2.5,
24-hour PM2.5, and/or 8-hour ozone in
2012, (2) quantify the impacts (i.e., air
quality contributions) of SO2 and NOX
emissions from upwind states on
downwind annual average and 24-hour
PM2.5 concentrations at monitoring sites
projected to be nonattainment or have
maintenance problems in 2012 for the
1997 annual and 2006 24-hour PM2.5
NAAQS, respectively, and (3) quantify
the impacts of NOX emissions from
upwind states on downwind 8-hour
ozone concentrations at monitoring sites
projected to be nonattainment or have
maintenance problems in 2012 for the
1997 ozone NAAQS.
To support the proposal, air quality
modeling was performed for four
emission scenarios: a 2005 base year, a
2012 ‘‘no CAIR’’ base case, a 2014 ‘‘no
CAIR’’ base case, and a 2014 control
case that reflects the emission
reductions expected from the FIPs. The
modeling for 2005 was used as the base
year for projecting air quality for each of
the 3 future-year scenarios. The 2012
base case modeling was used to identify
future nonattainment and maintenance
locations and to quantify the
contributions of emissions in upwind
states to annual average and 24-hour
PM2.5 and 8-hour ozone. The 2012 ozone
and PM2.5 concentrations were derived
by projecting 2003 through 2007 based
ambient ozone and/or PM2.5 data to the
future using the relative (percent)
change in modeled concentrations
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between 2005 and 2012. The 2014 base
case and 2014 control case modeling
were used to quantify the benefits of
this proposal.
In the proposed rule, EPA used the
Comprehensive Air Quality Model with
Extensions (CAMx) version 5.20 18 to
simulate ozone and PM2.5
concentrations for the 2005 base year
and the 2012 and 2014 future year
scenarios. The CAMx model
applications were designed to cover
states in the central and eastern U.S.
using a horizontal resolution of 12 x 12
km.19
CAMx contains ‘‘source
apportionment’’ tools that are designed
to quantify the contribution of
emissions from various sources and
areas to ozone and PM2.5 component
species in other downwind locations.
The source apportionment tools were
used to quantify the downwind
contributions of ozone and PM2.5 from
upwind states.
In the proposed rule, EPA used a
2005-based air quality modeling
platform which included 2005 base year
emissions and 2005 meteorology for
modeling ozone and PM2.5 with CAMx.
We received comments related to
several aspects of the air quality
modeling platform.
Comment: There was wide support
from commenters for the use of CAMx
as an appropriate, state-of-the science
air quality tool for use in the Transport
Rule. There were no comments that
suggested that EPA should use an
alternative model for quantifying
interstate transport. Many commenters
requested that EPA update the emission
inventories used for the Transport Rule
and then remodel the 2005 base year
and future year emissions using the
updated emissions and the most recent
version of CAMx to reassess interstate
transport for the final rule.
Response: For the final rule we have
updated our modeling using the latest
public release of CAMx (version 5.30)
and associated preprocessors. We have
also made numerous improvements to
the emission inventories for the 2005
base year as well as the 2012 and 2014
future year base cases in response to
public comments. The emissions
changes are described in section V.C.1.
The projection of future year
18 Comprehensive Air Quality Model with
Extensions Version 5 User’s Guide. Environ
International Corporation. Novato, CA. March 2009.
19 The 12 km domain was nested within a coarse
grid, 36 x 36 km modeling domain which covers the
lower 48 states and adjacent portions of Canada and
Mexico. Predictions from this Continental U.S.
(CONUS) domain were used to provide initial and
boundary concentrations for simulations in the 12
km domain.
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nonattainment and maintenance sites
and the quantification of ozone and
PM2.5 transport for the final rule are
based on modeling with CAMx v5.30
using the updated emission inventories.
The final rule air quality projections of
2012 nonattainment and maintenance
are described below. The final rule
interstate contributions are presented in
section V.D.
Comment: The performance
evaluation of the 2005 base year model
predictions for the proposed rule was
too cursory and did not provide
sufficient detail on model performance.
Commenters requested additional
analyses and spatial resolution
describing how well base year model
predictions compare to the
corresponding measured values.
Response: For the final rule we have
expanded the scope of the model
evaluation for 2005 to include a broader
suite of statistics to characterize
performance for individual subregions
of the eastern U.S. modeling domain.
The results of the performance
evaluation for the final rule 2005 base
year air quality modeling are described
in the Air Quality Modeling Final Rule
TSD.
Comment: The 2005 based modeling
platform should be updated to a more
recent year. There were several different
aspects of this comment. Some
commenters stated that EPA should be
using a more recent emission inventory
as a base year, due to identified changes
and updates to the inventories. Other
commenters stated that EPA should use
a more recent base year, due to a trend
of improvement in air quality over the
past few years. The commenters claim
that the 2005-based EPA modeling does
not account for large emission
reductions and air quality
improvements that have occurred over
the last several years.
Response: There are several reasons
why the use of a 2005 modeling base
case is both reasonable and, in fact,
necessary for the Transport Rule. As
explained in section V.B, above, because
the Transport Rule will replace CAIR,
EPA cannot consider reductions
associated with CAIR in the analytical
baseline emissions scenario. Thus, the
base year for the air quality projections
should be a year that represents
emissions before CAIR was in place (i.e.
2005). We are projecting emissions to a
future 2012 ‘‘no CAIR’’ case and
therefore want to best represent the air
quality change between 2005 and 2012,
without CAIR. To do this, we projected
emissions that existed before CAIR was
in effect and modeled the air quality
change that occurs between 2005 and
2012 without CAIR.
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A key consideration in our projection
methodology is the use of ambient data
to anchor the design value projections to
the future. The modeling is used in a
relative sense by multiplying the
modeled percent change in ozone or
PM2.5 species concentrations by the base
year ambient data. The ozone and PM2.5
modeling guidance recommends
projecting design values based on 5
years 20 of monitoring data that is
centered on the base model year. Using
2005 as a base emissions and
meteorological year entailed the use of
2003–2007 ambient air quality data (5
years of data centered about 2005). This
was a reasonable choice because the
majority of the ambient data from this
period was not impacted by CAIR
emission reductions.
After 2005, early emission reductions
of SO2 and NOX in response to CAIR
began to impact the measured air
quality concentrations. Since the
modeling projection methodology uses
both modeled and observed data, 2005
is the latest base year that we deemed
appropriate (before CAIR emission
reductions took place) for use in
projecting the measured air quality to a
2012 future year. The early years of the
5 year period (2003, 2004, and 2005)
were not impacted by CAIR.21 The last
2 years in the period (2006 and 2007)
were slightly impacted by CAIR
emission reductions. But the 5 year
average is weighted towards the middle
year of the period (2005), so the impact
of the years after CAIR promulgation
should be minimal.
The 2005 base year was also chosen
because it was an appropriate
meteorological year. In the eastern U.S.
there was relatively high ozone during
the summer of 2005 and relatively high
PM2.5 periods during the year. The
modeled attainment tests for both ozone
and 24-hour PM2.5 depend on having a
sufficient number of ‘‘high’’ modeled
days to project to the future. Modeling
a year that is not meteorologically
conducive to ozone and/or PM2.5
formation is discouraged by the
modeling guidance because a
meteorological year that is not
conducive to ozone or PM2.5 formation
may be less responsive to changes in
emissions in the future. Therefore,
projecting the relative change in ozone
or PM2.5 for a non-conducive base year
may underestimate the future change in
ozone and/or PM2.5 concentrations.
20 The modeling guidance recommends using a
five year weighted average design value. This is
calculated by averaging the three consecutive
design value periods of 2003–2005, 2004–2006, and
2005–2007.
21 The CAIR final rule was published on May 12,
2005.
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Additionally, all enforceable emission
reductions that occurred between 2005
and 2012 (other than those required
under CAIR) are captured by the
modeling system. Any enforceable nonEGU emission reductions due to
existing rules or the installation of
emissions controls after 2005 were
included in the 2012 base case
inventory. As explained above in
section V.B, to capture changes in EGU
emissions between 2005 and 2012, EPA
did not assume operation of all controls
installed during that time period, as
many of those controls were built in
response to CAIR. EPA used IPM to
project 2012 EGU emissions
incorporating all non-CAIR enforceable
emission constraints; operation of
existing pollution controls was taken
into account only where non-CAIR
constraints made it economic or legally
necessary to operate them. We also
accounted for permanent source
shutdowns that occurred after 2005.
Where possible, we incorporated
reported emission changes based on
comments to the proposed rule and a
subsequent emission inventory NODA.
Comment: Several commenters stated
that we used a ‘‘modeled + monitored’’
test in CAIR to identify future year
nonattainment receptors, but we only
used a modeled test in the Transport
Rule proposal. They suggest that we
should either go back to the ‘‘modeled
+ monitored’’ test or explain why we
should not use monitoring data in the
identification of nonattainment and
maintenance receptors. They say that
we should not base nonattainment and
maintenance receptors solely on
modeled violations. They also say that
we if we had looked at the most recent
ambient data we would see that most of
the modeled nonattainment and
maintenance receptors are already
attaining the ozone and/or PM2.5
NAAQS.
Response: In the identification of
future year nonattainment receptors for
CAIR, EPA used what was called the
‘‘modeled + monitored test’’. The most
recent ambient data (2001–2003 design
values at the time) were examined to
further verify that nonattainment was
still being measured at potential future
year nonattainment receptors. In the
proposed Transport Rule, EPA
identified future year nonattainment
and maintenance receptors based on
modeled projections of ambient data
from the 2003–2007 time period. The
future year receptors were not compared
to most recent ambient data to verify
that nonattainment still existed.
For the final Transport Rule, there are
several reasons that EPA did not
examine the most recent ambient data to
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verify that receptors were still
measuring nonattainment. The main
reason for dropping the ‘‘monitored’’
part of the modeled + monitored test is
the fact that the most recent monitoring
data (2007–2009 design values) include
large emission reductions from CAIR.
As explained in section V.B, above,
because the Transport Rule will replace
CAIR, we must model a future year base
case which does not assume that CAIR
is in place (a ‘‘no-CAIR’’ case). It is
simply not appropriate to examine the
current monitoring data, which
represent air quality with CAIR
emission reductions in place, and
compare the values to 2012 projected air
quality that is based on a no-CAIR
modeling case. As discussed above, we
modeled a 2005 base case with preCAIR emissions and a 2012 future ‘‘no
CAIR’’ case. The change in modeled air
quality is due to the non-CAIR
enforceable emission changes between
2005 and 2012 and therefore explicitly
does not take CAIR into account. As a
consequence, the 2012 projected design
values represent a unique case
(necessary for analyzing future air
quality without either CAIR or its
replacement Transport Rule in effect)
that cannot be represented by current
ambient data.
It is also important to note that all of
the projected 2012 design values are
based on projections of measured
ambient data. They are a combination of
measured data and modeled response
factors. Therefore, it is inaccurate to
imply that future year nonattainment
and maintenance receptors are solely
based on modeled projections. The
future year concentrations are firmly
rooted in base year measured ambient
data that have been projected to the
future using modeled data.
There are additional reasons for not
verifying the nonattainment and
maintenance receptors against the most
recent ambient data. In CAIR we did not
explicitly identify maintenance
receptors. In the Transport Rule
proposal we identified maintenance
receptors based on 2012 projections of
maximum design values from the 2003–
2007 period. Even though receptors may
be measuring attainment based on
recent data, they may still be at risk for
falling back into nonattainment.
Therefore, even if commenters argue
that recent data show that monitoring
sites should not be nonattainment
receptors (with which we disagree), the
same argument cannot be made
regarding maintenance receptors.
Clearly, receptors with recent ‘‘clean’’
ambient data may still experience
higher PM2.5 and/or ozone
concentrations in the future (based on
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meteorological and emission variability)
and therefore may be appropriate
maintenance receptors.
Comment: Several commenters claim
that the maintenance receptor
methodology overstates actual future
design values. They also recommend an
alternative methodology which takes
into account the downward trend in
observed PM2.5 concentrations over the
last 5+ years. The methodology would
remove the trend in the data where air
quality is improving over the period by
applying a linear fit to the data,
calculating the residuals and then
adding the residuals back to the average
of the data. Given a site with a
downward trend, this has the effect of
decreasing the calculated maximum
values from the early years in the period
and increasing the values from the end
years in the period.
Response: EPA continues to believe
that our approach to identify
maintenance receptors is reasonable and
appropriate. For the final rule, we
continue to identify maintenance
receptors by projecting the maximum
design value from the 2003–2007 period
to the future. The methodology assumes
that the combination of emissions and
meteorology that occurred in the base
period (which led to relatively high
ambient design values) could happen
again in the future (albeit at lower
emissions levels). There is no
information presented by the
commenters which explains why the
magnitude of base year design value
variability could not occur in the same
way in the future. The commenters cite
the downward trend in ambient data as
the reason why the EPA methodology is
not reasonable. However, in most cases,
the recent downward trend in ambient
data is due to a combination of ongoing
emission reductions (which includes
CAIR), variability in meteorology, and
depressed emissions due to the
recession. In fact, the most recent
ambient design value period (2007–
2009) is heavily influenced by
extremely low ozone and PM2.5
concentrations measured in 2009. The
2009 data are marked by relatively low
emissions due to cool summer weather
and ongoing effects of the recession. The
preliminary 22 2010 ambient data in the
eastern U.S. show that ozone and PM2.5
values were considerably higher in 2010
compared to 2009. In the states that are
included in the final Transport Rule
region, there were 158 ozone monitor
days that exceeded 84 ppb in 2009
compared to 412 monitor exceedance
22 The 2010 data is preliminary. Exceptional
event data has not been flagged and removed from
the reported data.
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days in 2010. For PM2.5, there were 251
monitor days that exceeded 35 μg/m 3 in
2009 compared to 417 monitor
exceedance days in 2010. Even though
the SO2 and NOX emissions were
generally lower in 2010, the observed
ozone and PM2.5 concentrations were
higher. This shows the important
influence of meteorology on ambient
concentrations. Clearly, the year to year
variability due to meteorology can be
large. We acknowledge the downward
trend in ambient data over the last few
years. But this does not mean that
conditions that led to high ozone
and/or PM2.5 in the 2003–2007 period
could not occur again in the future. The
2010 ambient data show that
meteorology can cause concentrations to
go back up, even though there is a
downward trend in emissions.
We also believe that the alternate
maintenance methodology presented by
the commenter is inappropriate. The
EPA modeling for 2012 (and 2014)
appropriately accounts for emission
reductions that occur after 2005 except
for those that should not be considered,
as explained in section V.B., because
they were required only by CAIR.
Therefore, the starting point design
values used to project to the future
should not be lowered to account for
emission reduction trends that occur
after 2005. Doing so would give ‘‘double
credit’’ to the more recent emission
reductions and provides an
inappropriate downward adjustment to
the early design value periods of the
2003–2007 period.
Comment: One commenter claims that
EPA did not follow our own modeling
guidance by not doing local scale
modeling in urban areas with high PM2.5
concentration gradients. They suggested
that the methodology to calculate future
year design values should have
included dispersion modeling to
calculate the change in concentration
over time of primary PM2.5 emissions.
Response: EPA modeling guidance for
PM2.5 attainment demonstrations
recommends photochemical grid
modeling to examine future year
changes in PM2.5 concentrations. There
are several optional aspects of the
modeling which are recommended in
specific cases. This includes a
recommendation for a ‘‘local area
analysis’’ using a dispersion model. An
area with relatively large local primary
PM2.5 concentration gradients may want
to do additional modeling to examine
the impacts of local controls on its
future year PM2.5 concentrations. This is
particularly important when local
controls of primary PM2.5 are included
as part of the attainment demonstration.
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As noted above, a ‘‘local area
analysis’’ is recommended as part of the
local attainment demonstration process
in specific situations. It is impractical
for EPA to perform this type of analysis
for each local area in the regional
Transport Rule. National rulemakings
are not attainment demonstrations. We
are not able to perform fine scale
analyses for each area. For the final rule
modeling, we have attempted to address
all emissions and modeling related
comments. We have updated the
modeling platform to use the latest
version of CAMx and are continuing to
model ozone and PM2.5 at 12km grid
resolution, which for PM2.5 is a more
refined grid resolution compared to the
CAIR modeling.
Additionally, there is no evidence
presented by the commenter that would
indicate that the future year PM2.5
concentrations from the Transport Rule
are biased high. In fact, depending on
the circumstances, local fine scale grid
or dispersion modeling may result in
lower or higher future year design
values. In a fine scale analysis, the
dominant local primary PM2.5 emissions
become a larger percentage of the PM2.5
concentrations. Therefore, if the local
emissions are forecast to decrease, fine
scale modeling may lead to lower future
design values. However, if the local
emissions are forecast to increase or stay
the same between the base and future
years, local modeling will likely show
higher future year design values
compared to a regional analysis. This
points to the fact that perceived biases
in modeling results may not always be
correct.
In sum, fine scale modeling of local
areas may lead to either higher or lower
future year design values. There is no
indication that EPA’s regional modeling
is biased in either direction. EPA’s
Transport Rule modeling generally
followed EPA’s modeling guidance and
is appropriate for the purpose of this
rulemaking.
Comment: One commenter completed
and submitted a detailed CAMx based
modeling analysis with a 2008 base year
and future years of 2014 and 2018. The
analysis shows that the majority of the
proposed rule 2012 nonattainment and
maintenance sites are already attaining
based on either 2006–2008 or 2007–
2009 ambient data. Based on this, the
commenter claims that air quality has
improved more rapidly than predicted
by EPA’s proposed rule modeling. Also,
based on the commenter’s 2014
modeling of CAIR emissions (including
utility consent decrees and state
programs), the commenter concludes
that no additional controls are needed
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
beyond CAIR to bring most or all sites
into attainment by 2014.
Response: As an initial matter, we
note that the basic question addressed
by the commenter, ‘‘whether additional
controls beyond CAIR are necessary,’’ is
not on point. As explained previously,
the D.C. Circuit remanded CAIR to EPA
and it remains in place only
temporarily. The question EPA must
answer in this rulemaking, therefore, is
not what controls in addition to CAIR
are necessary but what, if any,
restrictions on emissions must be put in
place to replace CAIR in order to satisfy
the requirements of section
110(a)(2)(D)(i)(I) of the CAA. For this
reason, and as explained in greater
detail in section V.B of this preamble,
any analysis of whether beyond CAIR
controls are necessary is irrelevant to
this rulemaking. Nonetheless, we have
carefully reviewed different aspects of
the commenter’s analysis. We
previously addressed comments related
to the use of more recent ambient data
to examine future year nonattainment
and maintenance receptors. As noted
above, the 2006–2008 and 2007–2009
ambient data is heavily influenced by
several factors. Among them are the
emissions reductions from CAIR, the
relatively low recent observed ozone
and PM2.5 concentrations at least
partially due to non-conducive
meteorology (particularly in 2009), and
the atypical suppression of emissions
due to the sharp recession. For all of
these reasons, we believe it is not
possible to directly compare the most
recent design values to the predicted
future year 2012 and 2014 design values
from the Transport Rule. In particular,
it is inappropriate to compare current
design values to EPA’s no-CAIR 2012
future year modeling results. As noted
in the comment summary, the
commenter’s modeling analysis
assumed that CAIR was in place in both
2008 and the future years. This is a
fundamentally different assumption
than the modeling EPA used to define
the Transport Rule nonattainment and
maintenance receptors in 2012 and is
inappropriate for purposes of the
Transport Rule for reasons described
above and in section V.B.
Additionally, EPA’s maintenance
methodology chooses the highest of
three base year design value periods
projected to the future. The commenter
only used a single design value period
in their analysis and therefore did not
fully examine maintenance issues. In
fact, the 2014 nonattainment modeling
receptors in the final Transport Rule
and the commenter’s modeling analysis
are similar. As documented in section
VI.D, in the 2014 final rule remedy case,
VerDate Mar<15>2010
19:20 Aug 05, 2011
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there is only one remaining
nonattainment area for ozone and one
remaining nonattainment area for
24-hour PM2.5. This is similar to the
modeling results presented in the
comments.23 However, EPA modeling
identifies additional maintenance
receptors in 2012 that continue to have
maintenance issues in 2014.
EPA also examined our ozone and
PM2.5 projection procedures to see if
there might be additional reasons for the
relatively lower current ambient design
values (and modeled design values in
the commenter’s analysis) compared to
the 2014 remedy modeled values. Upon
further analysis of EPA’s 24-hour
attainment test methodology, we noted
certain discrepancies between the
methodology and the calculation of the
ambient 24-hour design values. In the
proposed rule 24-hour attainment test,
for each PM2.5 monitor, we projected the
measured 98th percentile
concentrations from the 2003–2007
period to the future. A basic assumption
in this methodology is that the
distribution of high measured days in
the base period will be the same in the
future. For example, if the observed
98th percentile day is the 3rd high day
for a particular year, we assume that the
1st, 2nd, and 3rd high days (and
subsequent high days) in the future
remain in the same basic distribution.
Further examination of the proposed
rule modeling found that this is not
always the case. In situations where
there are large summer PM2.5
concentration reductions, some of the
high days may switch from the summer
in the base period to the winter in the
future period.
In order to better account for the
complicated future response in 24-hour
design values, we have updated the
24-hour attainment demonstration
methodology to more closely reflect the
way 24-hour design values are
calculated. In the revised methodology,
we do not assume that the temporal
distribution of high days in the base and
future periods will remain the same. We
project a larger set of ambient days from
the base period to the future and then
re-rank the entire set of days to find the
new future 98th percentile value (for
each year). More specifically, we project
the highest 8 days per quarter (32 days
per year) to the future and then re-rank
the 32 days to derive the future year
23 The purpose of this comparison is to note that
the modeling analyses are actually more similar
than the commenter implies. However, the
Transport Rule differs from the commenter’s
modeling due to the assumption that CAIR was in
place. CAIR and the Transport Rule differ in state
coverage and emission budgets. They are therefore
not directly comparable.
PO 00000
Frm 00026
Fmt 4701
Sfmt 4700
98th percentile concentrations. In the
case of the Transport Rule model
results, this has the effect of lowering
the future year 24-hour design values
compared to the old methodology. The
2012 base case design values for all
nonattainment and maintenance
receptors were either unchanged or
lower with the revised methodology.
3. How did EPA project future
nonattainment and maintenance for
annual PM2.5, 24-hour PM2.5, and 8-hour
ozone?
Final Rule: In general, the
methodology to project ozone and PM2.5
concentrations to the future year(s)
remains the same for the final rule. The
proposal modeling followed the
modeling guidance procedures for
projecting ambient design values to
future years. For the final rule, we
continue to follow the basic procedures
outlined in the guidance. The 8-hour
ozone and annual PM2.5 methodology
are unchanged from the proposal.
However, the 24-hour PM2.5
methodology has been updated in the
final rule to be more consistent with the
calculation of 24-hour PM2.5 design
values. There were also additional
minor updates to the ambient data.24
The methodology to identify
maintenance receptors is also
unchanged from the proposal. We
continue to use the maximum design
value (projected from the 5 year base
period) to calculate future year
maintenance receptors.
As noted in the proposal, EPA
considers that the maintenance concept
has two components: Year-to-year
variability in emissions and air quality,
and continued maintenance of the air
quality standard over time. The way that
EPA defined maintenance based on
year-to-year variability (as discussed in
detail here) directly affects the
requirements of this final rule. EPA also
considered whether further reductions
were necessary to ensure continued lack
of interference with maintenance of the
NAAQS over time (e.g., after 2014). EPA
concluded that in light of projected
emission trends, and also considering
the emission reductions from this
proposed rule, no further reductions are
required solely for this purpose at PM2.5
and ozone receptors for which we are
partially or fully determining significant
contribution for the current NAAQS.
(See discussion of emission trends in
Chapter 7 of TSD entitled ‘‘Emission
Inventories,’’ included in the docket for
the Transport Rule proposal.)
24 The base year design values were updated
based on the latest official data. See https://
www.epa.gov/airtrends/values.html.
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
a. Which ambient ozone and PM2.5 data
did EPA use for the purpose of
projecting future year concentrations?
The final rule modeling continues to
use a 2005 base case inventory and 2005
meteorology. Therefore, we continue to
use ambient data from the 2003–2007
period. For each monitoring site, all
valid design values (up to 3) from this
period were averaged together. Since
2005 is included in all three design
value periods, this has the effect of
creating a 5-year weighted average,
where the middle year is weighted 3
times, the 2nd and 4th years are
weighted twice, and the 1st and 5th
years are weighted once. We refer to this
as the 5-year weighted average value.
The 5-year weighted average values
were then projected to the future years
that were analyzed for this final rule.
The 2003–2005, 2004–2006, and 2005–
2007 design values are accessible at
https://www.epa.gov/airtrends/
values.html. The design values have
been updated based on the latest official
values. The official values have
exceptional events removed from the
calculations if they are flagged by states
and concurred with by EPA Regional
offices.
The procedures for projecting annual
average PM2.5 and 8-hour ozone
conform to the methodology in the
current attainment demonstration
modeling guidance.25
b. Projection of Future Annual and 24Hour PM2.5 Nonattainment and
Maintenance
(1) Methodology for Projecting Future
Annual PM2.5 Nonattainment and
Maintenance
For the final rule, annual PM2.5
modeling was performed for the 2005
base year emissions and for the 2012
base case as part of the approach for
projecting which locations are expected
to be in nonattainment and/or have
difficulty maintaining the PM2.5
standards in 2012. We refer to these
areas as nonattainment sites and
maintenance sites respectively.
Concentrations of PM2.5 in 2012 were
estimated by applying the modeled
2005-to-2012 relative change in PM2.5
species to each of the 3-year ambient
monitoring data periods (i.e., 2003–
2005, 2004–2006, and 2005–2007) to
obtain up to 3 future-year PM2.5 design
values for each monitoring site. We used
the highest of these projections at each
monitoring site to determine which sites
are expected to have maintenance
problems in 2012. We used the 5 year
weighted average of those projections to
determine which monitoring sites are
expected to be nonattainment in this
future year.
For the analysis of both
nonattainment and maintenance,
monitoring sites were included in the
analysis if they had at least one
complete design value in the 2003–2007
period.26 There were 721 monitoring
sites in the 12 km modeling domain
which had at least one complete design
value period for the annual PM2.5
NAAQS, and 722 sites which met this
criterion for the 24-hour NAAQS.27
EPA followed the procedures
recommended in the modeling guidance
for projecting PM2.5 by projecting
individual PM2.5 component species
and then summing these to calculate the
concentration of total PM2.5. EPA’s
Modeled Attainment Test Software
(MATS) was used to calculate the future
year design values. The software
(including documentation) is available
at: https://www.epa.gov/scram001/
modelingapps_mats.htm. Additional
details on the annual PM2.5
nonattainment and maintenance
projections methodology can be found
in the Air Quality Modeling Final Rule
TSD.
The 2012 annual PM2.5 design values
were calculated for each of the 721 sites.
48233
The calculated annual PM2.5 design
values are truncated after the second
decimal place.28 This is consistent with
the ambient monitoring data truncation
and rounding procedures for the annual
PM2.5 NAAQS. Any value that is greater
than or equal to 15.05 μg/m3 is rounded
to 15.1 μg/m3 and is considered to be
violating the NAAQS. Thus, sites with
projected 5-year weighted average
(‘‘average’’) annual PM2.5 design values
of 15.05 μg/m3 or greater are predicted
to be nonattainment sites. Sites with
projected maximum design values of
15.05 μg/m3 or greater are predicted to
be maintenance sites. Note that
nonattainment sites are also
maintenance sites because the
maximum design value is always greater
than or equal to the 5-year weighted
average. For ease of reference we use the
term ‘‘nonattainment sites’’ to refer to
those sites that are projected to exceed
the NAAQS based on both the average
and maximum design values. Those
sites that are projected to be attainment
based on the average design value, but
exceed the NAAQS based on the
maximum design value, are referred to
as maintenance sites. The monitoring
sites that we project to be nonattainment
and/or maintenance for the annual
PM2.5 NAAQS in the 2012 base case are
the nonattainment/maintenance
receptors used for assessing the
contribution of emissions in upwind
states to downwind nonattainment and
maintenance of the annual PM2.5
NAAQS.
Table V.C–1 contains the 2003–2007
base case period average and maximum
annual PM2.5 design values and the
corresponding 2012 base case average
and maximum design values for sites
projected to be nonattainment of the
annual PM2.5 NAAQS in 2012. Table
V.C–2 contains this same information
for projected 2012 maintenance sites.
TABLE V.C–1—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE ANNUAL PM2.5 DESIGN VALUES (μG/M3) AT
PROJECTED NONATTAINMENT SITES
ebenthall on DSK6TPTVN1PROD with RULES2
Monitor ID
010730023
010732003
131210039
171191007
261630033
........
........
........
........
........
County
Alabama ....................
Alabama ....................
Georgia .....................
Illinois ........................
Michigan ....................
Jefferson ...................
Jefferson ...................
Fulton ........................
Madison .....................
Wayne .......................
25 U.S. EPA, 2007: Guidance on the Use of Models
and Other Analyses for Demonstrating Attainment
of Air Quality Goals for Ozone, PM2.5, and Regional
Haze; Office of Air Quality Planning and Standards,
Research Triangle Park, NC.
VerDate Mar<15>2010
Average
design value
2003–2007
State
19:20 Aug 05, 2011
Jkt 223001
Maximum
design value
2003–2007
18.57
17.15
17.43
16.72
17.50
26 If there is only one complete design value, then
the nonattainment and maintenance design values
are the same.
27 Design values were only used if they were
deemed to be officially complete based on CFR 40
Part 50 Appendix N. The completeness criteria for
the annual and 24-hour PM2.5 NAAQS are different.
PO 00000
Frm 00027
Fmt 4701
Sfmt 4700
Final rule
average design
value 2012
18.94
17.69
17.47
17.01
18.16
16.15
15.16
15.07
15.46
15.73
Final rule
maximum design
value 2012
16.46
15.64
15.10
15.73
16.32
Therefore, there are fewer complete sites for the
annual NAAQS.
28 For example, a calculated annual average
concentration of 14.94753 * * * becomes 14.94
when digits beyond two places to the right of the
decimal are truncated.
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
TABLE V.C–1—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE ANNUAL PM2.5 DESIGN VALUES (μG/M3) AT
PROJECTED NONATTAINMENT SITES—Continued
Monitor ID
390350038
390350045
390350060
390610014
390610042
390618001
420030064
Average
design value
2003–2007
State
........
........
........
........
........
........
........
County
Ohio ...........................
Ohio ...........................
Ohio ...........................
Ohio ...........................
Ohio ...........................
Ohio ...........................
Pennsylvania .............
Cuyahoga ..................
Cuyahoga ..................
Cuyahoga ..................
Hamilton ....................
Hamilton ....................
Hamilton ....................
Allegheny ..................
Maximum
design value
2003–2007
17.37
16.47
17.11
17.29
16.85
17.54
20.31
Final rule
average design
value 2012
18.10
16.98
17.66
17.53
17.25
17.90
20.75
15.99
15.14
15.67
15.76
15.40
16.01
17.94
Final rule
maximum design
value 2012
16.66
15.61
16.18
15.98
15.77
16.33
18.33
TABLE V.C–2—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE ANNUAL PM2.5 DESIGN VALUES (μG/M3) AT
PROJECTED MAINTENANCE-ONLY SITES
Monitor ID
ebenthall on DSK6TPTVN1PROD with RULES2
180970081
180970083
390350065
390617001
........
........
........
........
County
Indiana ......................
Indiana ......................
Ohio ...........................
Ohio ...........................
Marion .......................
Marion .......................
Cuyahoga ..................
Hamilton ....................
(2) Methodology for Projecting Future
24-Hour PM2.5 Nonattainment and
Maintenance
The procedures for calculating the
future year 24-hour PM2.5 design values
have been updated for the final rule.29
The revised procedures are in response
to comments which noted relatively
high future year 24-hour PM2.5 design
values in EPA’s modeling of the
proposed Transport Rule. The updates
are intended to make the projection
methodology more consistent with the
procedures for calculating ambient
design values.
As noted above, for the proposed
Transport Rule EPA projected for each
PM2.5 monitor the measured 98th
percentile concentrations from the
2003–2007 period to the future. As an
additional check, we also projected the
next highest concentrations from the
three calendar quarters in each year
when the 98th percentile did not occur
in the 2003–2007 base period, to ensure
that the future year 98th percentile did
not switch seasons in the future year
compared to the base year. A basic
assumption in this methodology is that
the distribution of high measured days
in the base period will be the same in
the future.
In other words, EPA assumed at
proposal that the 98th-percentile day
could only be displaced ‘‘from below’’
in the instance that a different day’s
future concentration exceeded the
original 98th-percentile day’s future
concentration. In that case, the original
29 There were no updates to the ozone and annual
PM2.5 attainment test methodology.
VerDate Mar<15>2010
Average
design value
2003–2007
State
19:20 Aug 05, 2011
Jkt 223001
Maximum
design value
2003–2007
16.05
15.90
15.97
16.17
98th-percentile day may become the
97th- or 96th-percentile day in the
future year; EPA accounted for this
possibility at proposal. EPA did not,
however, consider that the 98thpercentile day could also be displaced
‘‘from above’’ in the instance that
higher-concentration days in the base
period were projected to have future
concentrations lower than the original
98th-percentile day’s future
concentration. In that case, the original
98th-percentile day may become the
99th- or 100th-percentile day. Because
EPA continued to use that day’s future
concentration to determine the
monitor’s future design value at
proposal, this sometimes resulted in
overstatement of future-year design
values for 24-hour PM2.5 monitoring
sites whose seasonal distribution of
highest-concentration 24-hour PM2.5
days changed between the 2003–2007
period and the future year modeling.
Examination of the proposed rule
remedy modeling (2014 remedy case)
showed that many of the highest PM2.5
days switched from the summer in the
base period to the winter in the future
period. This is especially true in areas
of the upper Midwest which experience
both high summer and winter PM2.5
episodes.
In the revised methodology, we do not
assume that the seasonal distribution of
high days in the base period years and
future years will remain the same. We
project a larger set of ambient days from
the base period to the future and then
re-rank the entire set of days to find the
new future 98th percentile value (for
PO 00000
Frm 00028
Fmt 4701
Sfmt 4700
Final rule
average design
value 2012
16.36
16.27
16.44
16.56
14.86
14.71
14.67
14.74
Final rule
maximum design
value 2012
15.16
15.06
15.10
15.10
each year). More specifically, we project
the highest 8 days per quarter (32 days
per year) to the future and then re-rank
the 32 days to derive the future year
98th percentile concentrations. In the
case of the Transport Rule model
results, this has the effect of lowering
the future year 24-hour design values
compared to the old methodology.
The modeling guidance
recommendations for state attainment
demonstrations have been updated to
reflect the changes outlined above.
Further details on the 24-hour PM2.5
design value calculations can be found
in the Air Quality Modeling Final Rule
TSD. The above procedures for
determining future year 24-hour PM2.5
concentrations were applied for each
site. The 24-hour PM2.5 design values
are truncated after the first decimal
place. This approach is consistent with
the ambient data truncation and
rounding procedures for the 24-hour
PM2.5 NAAQS. Any value that is greater
than or equal to 35.5 μg/m3 is rounded
to 36 μg/m3 and is violating the
NAAQS. Sites with future year 5-year
weighted average design values of 35.5
μg/m3 or greater, based on the projection
of 5-year weighted average
concentrations, are predicted to be
nonattainment. Sites with future year
maximum design values of 35.5 μg/m3
or greater are predicted to be
maintenance sites. Note that
nonattainment sites for the 24-hour
NAAQS are also maintenance sites
because the maximum design value is
always greater than or equal to the 5year weighted average. The monitoring
E:\FR\FM\08AUR2.SGM
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
sites that we project to be nonattainment
and/or maintenance for the 24-hour
PM2.5 NAAQS in the 2012 base case are
the nonattainment/maintenance
receptors used for assessing the
contribution of emissions in upwind
states to downwind nonattainment and
maintenance of 24-hour PM2.5 NAAQS
as part of this final rule.
Table V.C–3 contains the 2003–2007
base period average and maximum 24hour PM2.5 design values and the 2012
48235
base case average and maximum design
values for sites projected to be 2012
nonattainment of the 24-hour PM2.5
NAAQS in 2012. Table V.C–4 contains
this same information for projected 2012
24-hour maintenance sites.
TABLE V.C–3—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 24-HOUR PM2.5 DESIGN VALUES (μG/M3) AT
PROJECTED NONATTAINMENT SITES
Monitor ID
010730023
170311016
171191007
180970043
180970066
180970081
261470005
261630015
261630016
261630019
261630033
390350038
390350060
420030064
420030093
420030116
420070014
420710007
540090011
550790043
Average
design value
2003–2007
State
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
County
Alabama ....................
Illinois ........................
Illinois ........................
Indiana ......................
Indiana ......................
Indiana ......................
Michigan ....................
Michigan ....................
Michigan ....................
Michigan ....................
Michigan ....................
Ohio ...........................
Ohio ...........................
Pennsylvania .............
Pennsylvania .............
Pennsylvania .............
Pennsylvania .............
Pennsylvania .............
West Virginia .............
Wisconsin ..................
Jefferson ...................
Cook ..........................
Madison .....................
Marion .......................
Marion .......................
Marion .......................
St Clair ......................
Wayne .......................
Wayne .......................
Wayne .......................
Wayne .......................
Cuyahoga ..................
Cuyahoga ..................
Allegheny ..................
Allegheny ..................
Allegheny ..................
Beaver .......................
Lancaster ..................
Brooke .......................
Milwaukee .................
Maximum
design value
2003–2007
44.0
43.0
39.1
38.4
38.3
38.2
39.6
40.1
42.9
40.9
43.8
44.2
42.1
64.2
45.6
42.5
43.4
40.8
43.9
39.9
Final rule
average design
value 2012
44.2
46.3
40.1
39.9
39.6
39.2
40.6
40.6
45.4
41.4
44.2
47.0
45.7
68.2
51.5
42.5
44.6
44.0
44.9
40.8
36.9
37.5
36.5
35.7
35.7
35.8
36.2
35.5
38.9
37.3
39.4
39.4
37.7
56.7
39.1
35.5
36.2
35.9
37.5
36.2
Final rule
maximum design
value 2012
37.3
40.4
36.8
37.1
36.9
36.9
37.1
36.0
41.2
37.8
39.8
41.8
40.8
59.9
44.3
35.5
37.4
38.3
38.3
37.1
TABLE V.C–4—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 24-HOUR PM2.5 DESIGN VALUES (μG/M3) AT
PROJECTED MAINTENANCE-ONLY SITES
Monitor ID
ebenthall on DSK6TPTVN1PROD with RULES2
010732003
170310052
170312001
170313301
170316005
171190023
180890022
180890026
261610008
390170003
390350045
390350065
390618001
390811001
391130032
420031008
420031301
420033007
421330008
550790010
550790026
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
........
County
Alabama ....................
Illinois ........................
Illinois ........................
Illinois ........................
Illinois ........................
Illinois ........................
Indiana ......................
Indiana ......................
Michigan ....................
Ohio ...........................
Ohio ...........................
Ohio ...........................
Ohio ...........................
Ohio ...........................
Ohio ...........................
Pennsylvania .............
Pennsylvania .............
Pennsylvania .............
Pennsylvania .............
Wisconsin ..................
Wisconsin ..................
Jefferson ...................
Cook ..........................
Cook ..........................
Cook ..........................
Cook ..........................
Madison .....................
Lake ..........................
Lake ..........................
Washtenaw ...............
Butler .........................
Cuyahoga ..................
Cuyahoga ..................
Hamilton ....................
Jefferson ...................
Montgomery ..............
Allegheny ..................
Allegheny ..................
Allegheny ..................
York ...........................
Milwaukee .................
Milwaukee .................
(3) Methodology for Projecting Future 8Hour Ozone Nonattainment and
Maintenance
The final rule methodology to
calculate 8-hour ozone nonattainment
and maintenance receptors is identical
to the proposed rule. The May-to-
VerDate Mar<15>2010
Average
design value
2003–2007
State
19:20 Aug 05, 2011
Jkt 223001
Maximum
design value
2003–2007
40.3
40.2
37.7
40.2
39.1
37.3
38.9
38.4
39.4
39.2
38.5
38.6
40.6
41.9
37.8
41.3
40.3
37.5
38.2
38.6
37.3
September 24-hour maximum 8-hour
average concentrations from the 2005
base case and the 2012 base case were
used to project ambient design values to
2012. The following is a brief summary
of the future year 8-hour average ozone
calculations. Additional details are
PO 00000
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Fmt 4701
Sfmt 4700
Final rule
average design
value 2012
40.8
41.4
40.6
43.3
41.8
38.1
44.0
41.3
40.8
41.1
41.5
41.0
40.9
45.5
40.0
42.8
42.4
43.1
40.7
40.0
41.3
35.3
34.9
33.6
34.9
34.1
35.1
34.9
34.0
35.0
34.4
34.7
34.9
35.2
34.5
33.6
35.0
33.9
32.3
33.3
35.4
33.6
Final rule
maximum design
value 2012
35.9
36.0
36.1
37.6
36.4
35.8
39.5
37.0
36.3
36.5
38.1
37.6
35.8
37.8
35.6
36.3
35.6
37.3
36.0
36.7
37.2
provided in the Air Quality Modeling
Final Rule TSD.
We are using the base period 2003–
2007 ambient ozone design value data
for projecting future year design values.
Relative response factors (RRF) for each
monitoring site were calculated as the
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percent change in ozone on days with
modeled ozone greater than 85 ppb.30
The maximum future design value is
calculated by projecting design values
for each of the three base periods (2003–
2005, 2004–2006, and 2005–2007)
separately. The highest of the three
future values is the maximum design
value. This maximum value is used to
identify the 8-hour ozone maintenance
receptors.
The future year design values are
truncated to integers in units of ppb.
This approach is consistent with the
ambient data truncation and rounding
procedures for the 8-hour ozone
NAAQS. Future year design values that
are greater than or equal to 85 ppb are
considered to be violating the NAAQS.
Sites with future year 5-year weighted
average design values of 85 ppb or
greater are predicted to be
nonattainment. Sites with future year
maximum design values of 85 ppb or
greater are predicted to be future year
maintenance sites. Note that, as
described previously for the annual and
24-hour PM2.5 NAAQS, nonattainment
sites for the ozone NAAQS are also
maintenance sites because the
maximum design value is always greater
than or equal to the 5-year weighted
average. The monitoring sites that we
project to be nonattainment and/or
maintenance for the 8-hour ozone
NAAQS in the 2012 base case are the
nonattainment/maintenance receptors
used for assessing the contribution of
emissions in upwind states to
downwind nonattainment and
maintenance of ozone NAAQS.
Table V.C–5 contains the 2003–2007
base period average and maximum
8-hour ozone design values and the
2012 base case average and maximum
design values for sites projected to be
2012 nonattainment of the 8-hour ozone
NAAQS in 2012. Table V.C–6 contains
this same information for projected 2012
8-hour ozone maintenance sites.
TABLE V.C–5—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 8-HOUR OZONE DESIGN VALUES (PPB) AT
PROJECTED NONATTAINMENT SITES
Monitor ID
220330003
480391004
482010051
482010055
482010062
482010066
482011039
Average
design value
2003–2007
State
........
........
........
........
........
........
........
County
Louisiana ...................
Texas ........................
Texas ........................
Texas ........................
Texas ........................
Texas ........................
Texas ........................
East Baton Rouge .....
Brazoria .....................
Harris .........................
Harris .........................
Harris .........................
Harris .........................
Harris .........................
Maximum
design value
2003–2007
92.0
94.7
93.0
100.7
95.7
92.3
96.3
Final rule
average design
value 2012
96
97
98
103
99
96
100
85.6
86.7
86.1
93.3
88.8
87.1
88.8
Final rule
maximum design
value 2012
89.3
88.8
90.8
95.4
91.8
90.6
92.2
TABLE V.C–6—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 8-HOUR OZONE DESIGN VALUES (PPB) AT
PROJECTED MAINTENANCE-ONLY SITES
Monitor ID
090011123
090093002
240251001
260050003
482010024
482010029
482011015
482011035
482011050
........
........
........
........
........
........
........
........
........
County
Connecticut ...............
Connecticut ...............
Maryland ...................
Michigan ....................
Texas ........................
Texas ........................
Texas ........................
Texas ........................
Texas ........................
Fairfield .....................
New Haven ...............
Harford ......................
Allegan ......................
Harris .........................
Harris .........................
Harris .........................
Harris .........................
Harris .........................
D. Pollution Transport From Upwind
States
1. Choice of Air Quality Thresholds
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a. Thresholds
In this action, EPA uses air quality
thresholds to identify linkages between
upwind states and downwind
nonattainment and maintenance
receptors. States whose contributions to
a specific receptor meet or exceed the
thresholds identified are considered
linked to that receptor; those states’
emissions (and available emission
reductions) are analyzed further in the
30 As specified in the attainment demonstration
modeling guidance, if there are less than 10
modeled days > 85 ppb, then the threshold is
VerDate Mar<15>2010
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design value
2003–2007
State
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Maximum
design value
2003–2007
92.3
90.3
92.7
90.0
88.0
91.7
89.0
86.3
89.3
Average design
value 2012
94
93
94
93
92
93
96
95
92
83.9
82.7
84.4
82.4
83.4
84.2
82.4
79.9
82.8
Maximum design
value 2012
85.5
85.1
85.6
85.1
87.2
85.4
88.9
88.0
85.4
second step of EPA’s significant
contribution analysis. States whose
contributions are below the thresholds
are not included in the Transport Rule
for that NAAQS. In other words, we are
finding that states whose contributions
are below these thresholds do not
significantly contribute to
nonattainment or interfere with
maintenance of the relevant NAAQS.
We use separate air quality thresholds
for annual PM2.5, 24-hour PM2.5, and
8-hour ozone. Each air quality threshold
is calculated as 1 percent of the
NAAQS. Specifically, we use an air
quality threshold of 0.15 μg/m3 for
annual PM2.5, 0.35 μg/m3 for 24-hour
PM2.5, and 0.8 ppb for 8-hour ozone.
These are the same air quality
thresholds we proposed.
EPA received a number of comments
on the thresholds we proposed, and
those comments and EPA’s responses
are discussed below.
lowered in 1 ppb increments (to as low as 70 ppb)
until there are 10 days. If there are less than 5 days
> 70 ppb, then an RRF calculation is not completed
for that site.
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b. General Comments on the Overall
Stringency and Use of 1 Percent of the
NAAQS
EPA received numerous comments
supporting and opposing the proposed
thresholds. A number of commenters
cited support for EPA’s approach. Some
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commenters believed that use of a 1
percent threshold was too stringent, and
recommended that EPA should use a
threshold greater than 1 percent. Others
believed that 1 percent was not stringent
enough, and they recommended using a
lower value such as 0.5 percent. EPA
believes that for both PM2.5 and for
ozone, it is appropriate to use a
threshold of 1 percent of the NAAQS for
identifying states whose contributions
do not significantly contribute to
nonattainment or interfere with
maintenance of the relevant NAAQS;
therefore, EPA has retained the 1
percent threshold for the reasons
described below.
As we found at the time of CAIR,
EPA’s analysis of base case PM2.5
transport shows that, in general, PM2.5
nonattainment problems result from the
combined impact of relatively small
contributions from many upwind states,
along with contributions from in-state
sources and, in some cases,
substantially larger contributions from a
subset of particular upwind states. (See
section II of the January 2004 CAIR
proposal, 69 FR 4575–87).
In the 1998 NOX SIP Call (63 FR
57456, October 27, 1998) and in CAIR,
EPA also found important contributions
from multiple upwind states. As a result
of the upwind ‘‘collective
contributions,’’ EPA determined that it
is appropriate to use a low air quality
threshold when analyzing upwind
states’ contributions to downwind
states’ attainment and maintenance
problems for ozone as well as PM2.5.
Low threshold values are also
warranted, as EPA discussed in the
notices for CAIR, due to adverse health
impacts associated with ambient PM2.5
and ozone even at low concentrations
(See relevant portions of the CAIR
proposal notice (63 FR 4583–84) and the
CAIR final rule notice (70 FR 25189–
25192)).
To aid in responding to comments,
EPA has compiled the contribution
modeling results to analyze the impact
of different possible thresholds. This
analysis demonstrates the
reasonableness of using the 1 percent
threshold to account for the combined
impact of relatively small contributions
from many upwind states (see Air
Quality Modeling Final Rule TSD). In
this analysis, EPA identifies for annual
PM2.5 (sulfate and nitrate), 24-hour
PM2.5 (sulfate and nitrate), and 8-hour
ozone receptors: (1) Total upwind state
contributions, and (2) the amount of the
total upwind state contribution that is
captured at thresholds of 1 percent, 5
percent and 0.5 percent of the NAAQS.
EPA continues to find that the total
‘‘collective contribution’’ from upwind
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sources represents a large portion of
PM2.5 and ozone at downwind locations
and that the total amount of transport is
composed of the individual contribution
from numerous upwind states.
The analysis shows that the 1 percent
threshold captures a high percentage of
the total pollution transport affecting
downwind states for both PM2.5 and
ozone. In response to commenters who
advocated a higher threshold, EPA
observes that higher thresholds would
exclude increasingly large percentages
of total transport, which we do not
believe would be appropriate. For
example, a 5 percent threshold would
exclude the majority—and for annual
PM, more than 80 percent—of interstate
pollution transport affecting the
downwind state receptors analyzed
(based on the average percentage of total
interstate transport across all receptors
captured at the 5 percent threshold).
In response to commenters who
advocated a lower threshold, EPA
observes that the analysis shows that a
lower threshold such as 0.5 percent
would result in relatively modest
increases in the overall percentages of
PM2.5 and ozone pollution transport
captured relative to the amounts
captured at the 1 percent level. A 0.5
percent threshold could lead to
emission reduction responsibilities in
additional states that individually have
a very small impact on those receptors—
an indicator that emission controls in
those states are likely to have a smaller
air quality impact at the downwind
receptor. We are not convinced that
selecting a threshold below 1 percent is
necessary or desirable. A strong
indication that the amount of pollution
transport being excluded from
consideration is not excessive is that the
controls required under this rule are
projected to eliminate nonattainment
and maintenance problems with air
quality standards at most downwind
state receptors.
Considering the combined downwind
impact of multiple upwind states, the
health effects of low levels of PM2.5 and
ozone pollution, and EPA’s previous use
of a 1 percent threshold for PM2.5 in
CAIR, EPA’s judgment is that the 1
percent threshold is a reasonable choice.
Some commenters noted that the
PM2.5 thresholds used for this rule are
less than the ‘‘significant impact levels’’
(SILs) used for permitting programs. As
EPA stated at the time of CAIR, since
the thresholds referred to by the
commenters serve different purposes
than the CAIR threshold for significant
contribution, it does not follow that they
should be made equivalent (70 FR
25191; May 12, 2005).
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48237
c. Comments on the Rounding
Conventions for PM2.5
In the final Transport Rule, EPA is
using two-digit values for the PM2.5
thresholds. Some commenters suggested
that EPA should use the same rounding
convention for annual PM2.5 used in
CAIR; that is, the threshold should be
0.2 μg/m3 rather than 0.15 μg/m3. The
reasons for EPA’s decision are below.
The rationale for the single digit value
for the final CAIR rule was that a single
digit is consistent with the EPA
monitoring data reporting requirements
in Part 50, Appendix N, section 4.3.
These reporting requirements specify
that design values for the annual PM2.5
standard shall be rounded to the tenths
place (decimals 0.05 and greater are
rounded up to the next 0.1, and any
decimal lower than 0.05 is rounded
down to the nearest 0.1).
Because the design value is to be
reported only to the nearest 0.1 μg/m3,
EPA deemed it preferable for the final
CAIR to select the threshold value at the
nearest 0.1 μg/m3 as well, and hence
one percent of the 15 μg/m3, rounded to
the nearest 0.1 μg/m3 became 0.2 μg/m3.
The reporting requirements in section
Part 50, Appendix N, section 4.3 for the
24-hour PM2.5 standard state that design
values for this standard shall be
rounded to the nearest 1 μg/m3
(decimals 0.5 and greater are rounded
up to the nearest whole number, and
any decimal lower than 0.5 is rounded
down to the nearest whole number).
If the approach used in CAIR were to
be used to establish an air quality
threshold for the 24-hour PM2.5 NAAQS
(which CAIR did not address), the
resulting threshold would be zero. One
percent of the 24-hour standard is 0.35
μg/m3, and rounding to the nearest
whole number would yield an air
quality threshold of zero. Thus if we
were to apply the same rationale used
to develop the annual PM2.5 threshold
for the final CAIR, there would be no air
quality threshold for 24-hour PM2.5,
which EPA believes to be counterintuitive and unworkable as an
approach for assessing interstate
contributions.
Therefore, for this rule, EPA proposed
and is now finalizing an approach that
decouples the precision of the air
quality thresholds from the monitoring
reporting requirements, and uses 2-digit
values representing one percent of the
PM2.5 NAAQS; that is, 0.15 μg/m3 for
the annual standard, and 0.35 μg/m3 for
the 24-hour standard. EPA believes
there are a number of considerations
favoring this approach. First, it provides
for a consistent approach for the annual
and 24-hour standards. Second, the
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approach is readily applicable to any
current and future NAAQS and would
automatically adjust the stringency of
the transport threshold to maintain a
constant relationship with the
stringency of the relevant NAAQS as
they are revised. The CAIR approach
would not allow for this continuity: For
example, if EPA were to retain the CAIR
approach for the annual standard, any
future lowering of the PM2.5 NAAQS to
below 15 μg/m3 would reduce the air
quality threshold to the same outcome:
0.1 μg/m3. This would occur because
any value less than 0.15 μg/m3 would
round to 0.1 μg/m3 (assuming EPA
would not round down to zero for the
reasons described above), which means
that the air quality threshold would
have a different relative stringency to
each possible future NAAQS value. For
the above reasons, EPA believes the use
of two-digit thresholds for both annual
PM2.5 and 24-hour PM2.5 in the final rule
is both reasonable and appropriate. The
departure from the approach used for
annual PM2.5 in CAIR is appropriate
given the additional considerations that
were not in existence at the time of the
final CAIR, and the importance of using
a consistent approach to developing air
quality thresholds for all NAAQS
addressed by this rule as well as future
NAAQS considered in future transportrelated actions.
Some of these commenters suggested
using the CAIR rounding conventions
coupled with use of a 1-digit threshold
of 0.4 μg/m3 for 24-hour PM2.5. EPA
considered the approach suggested by
commenters, but determined that the
proposed approach is more appropriate.
First, adhering to the rounding
conventions used for CAIR for annual
PM2.5 is not workable for the 24-hour
standard because the rounding
convention would yield a threshold of
zero. Rounding alternatively to 0.4 μg/
m3 would require EPA to find a basis for
rounding the threshold to the nearest
0.1 μg/m3 instead of using a strict
application of 1 percent; we do not see
any basis for such rounding at this time.
d. Comments Related to the MultiFactor Test EPA Used for Ozone in
CAIR
Some commenters suggested that, for
ozone, EPA should use the multiplemetric test we used for CAIR, and not
a simple threshold based on 1 percent
of the NAAQS. With respect to ozone,
EPA proposed in the Transport Rule to
take a more straightforward approach to
air quality thresholds than the multifactor approaches used for the NOX SIP
Call and the CAIR. As proposed, EPA is
using a contribution metric that is
calculated based on the multi-day
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average contribution. This metric is
compared to one percent of the 1997
8-hour ozone standard of 0.08 ppm.
Under this approach, one percent of the
NAAQS is a value of 0.8 ppb.
Contributions of 0.8 ppb and higher are
above the threshold; ozone
contributions less than 0.8 ppb are
below the threshold. In past
rulemakings (e.g., CAIR) EPA used
multiple ozone metrics, including the
average contribution and maximum
single day contribution to downwind
nonattainment. EPA believes the
average contribution (calculated over
multiple high ozone days) is a robust
metric compared to the maximum
contribution on a single day. EPA
believes that this approach is preferable
because it uses a robust metric, it is
consistent with the approach for PM2.5,
and it provides for a consistent
approach that takes into account, and is
applicable to, any future ozone
standards below 0.08 ppm.
One of these commenters suggested
that the 0.8 ppb threshold value was
substantially more stringent than the 2
ppb screening test which was a part of
the approach used for CAIR. The 1
percent threshold (0.8 ppb) is not
substantially more stringent than the
previous 2 ppb test because of
differences in the metrics used to
evaluate contributions against these two
levels. The 2 ppb test was evaluated
using the highest single day absolute
model-predicted downwind
contribution from an upwind state. The
1 percent threshold is evaluated based
on the average relative downwind
impact calculated over multiple days.
Therefore, it is appropriate to set a
lower concentration threshold for use
with the average contribution metric
calculated for the Transport Rule. More
details on the calculation of the
contribution metric can be found in the
Air Quality Modeling Final Rule TSD.
As noted above, EPA believes that the
approach used for the proposed rule
provides for a simplified, yet robust
approach compared to CAIR.
Accordingly, for the final rule we have
retained the approach used for the
proposal.
One commenter suggested that EPA
retain the CAIR multiple-factor
approach for ozone, and to apply that
same approach to 24-hour PM2.5. As
noted above, EPA is not retaining this
approach for ozone, and for similar
reasons we believe a multi-factor
approach is not needed for 24-hour
PM2.5. The approach based on 1 percent
of the NAAQS is consistent with the
form of the 24-hour standard. In
addition, this approach is based on
contributions on days with high 24-hour
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PM2.5 predictions and therefore is
relevant for characterizing transport
during short-term high PM2.5 episodic
conditions.
e. Comments on the Relationship to
Measurement Precision
Other commenters suggested that, as
did commenters on the thresholds used
in CAIR, EPA should take into
consideration the measurement
precision of existing PM2.5 monitors in
setting the thresholds for the Transport
Rule. EPA disagrees that monitoring
precision is relevant to determining the
amount of modeled PM2.5 or ozone that
should be considered to be a
‘‘contribution’’ from upwind states since
states are not required to, nor would it
be possible for them to, measure their
individual state impacts on downwind
receptors. The approach for eliminating
significant contribution is based on the
implementation of enforceable
emissions budgets and not on a
measurement of ambient air quality.
Thus, EPA believes it is a reasonable
exercise of its discretion to de-couple
monitoring precision from the choice of
contribution states.
f. Comments Related to the CAIR Court
Decision
Commenters recommended that EPA
should have retained the criteria used
for CAIR because those values were
upheld by the Court. As noted above,
EPA could not have used the approach
for annual PM2.5 that was used in CAIR
to develop a 24-hour PM2.5 threshold, as
that approach would have yielded a
threshold value of zero 24-hour PM2.5.
Further, nothing in the North Carolina
opinion suggests that the thresholds and
methods used in CAIR were the only
possible approaches EPA could have
used, that they were preferable to other
approaches, or that other alternatives
would not be acceptable. Instead, the
Court upheld the 0.2 μg/m3 threshold
used for PM2.5 on the grounds that it
was not ‘‘wholly unsupported by the
record’’ (North Carolina, 531 F.3d at
915). EPA has determined for reasons
explained in the record that the
thresholds used in this final rule are
both reasonable and appropriate for use
in this final rule.
2. Approach for Identifying Contributing
Upwind States
This section documents the
procedures used by EPA to quantify the
contribution of emissions in specific
upwind states to air quality
concentrations in projected 2012
downwind nonattainment and
maintenance locations for annual PM2.5,
24-hour PM2.5, and 8-hour ozone. In the
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proposed rule EPA used CAMx
photochemical source apportionment
modeling to quantify the impact of
emissions in specific upwind states on
projected downwind nonattainment and
maintenance receptors for both PM2.5
and 8-hour ozone. In this modeling we
tracked the ozone and PM2.5 formed
from 2012 base case emissions from
anthropogenic sources in each upwind
state in the 12 km modeling domain.
The CAMx Particulate Source
Apportionment Technique (PSAT) was
used to calculate downwind
contributions to nonattainment and
maintenance of PM2.5. In the PSAT
simulation NOX emissions are tracked to
particulate nitrate concentrations, SO2
emissions are tracked to particulate
sulfate concentrations, and primary
particulates (organic carbon, elemental
carbon, and other PM2.5) are tracked as
primary particulates. As described
earlier in section V.A, the nitrate and
sulfate contributions were combined
and used to evaluate interstate
contributions of PM2.5.
The CAMx Ozone Source
Apportionment Technique (OSAT) was
used to calculate downwind 8-hour
ozone contributions to nonattainment
and maintenance. OSAT tracks the
formation of ozone from NOX and VOC
emissions.
Comment: Three commenters stated
that the CAMx source apportionment
techniques used for the proposed rule
reflect state-of-the science technologies
and are appropriate for evaluating
interstate transport. One commenter
asked that EPA do more to demonstrate
that the PSAT and OSAT techniques
give reliable answers, although no
suggestions were provided on how this
might be done. Another commenter said
that the results of the contribution
analyses were consistent with the
results of their scientific research.
Response: EPA is not changing its
conclusion that the CAMx source
apportionment techniques are
appropriate for quantifying interstate
transport. The strength of the source
apportionment technique is that all
modeled ozone and/or PM2.5 mass at a
given location in the modeling domain
is tracked back to specific sources of
emissions and boundary conditions to
fully characterize culpable sources. No
commenters provided technically valid
analyses indicating that EPA’s use of
CAMx source apportionment techniques
are inappropriate for the purposes of the
Transport Rule.
Comment: We received comments
that certain states included in the
proposed rule should be excluded from
the final rule because EPA had
overstated the 2012 emissions in these
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states. Commenter requested that we
redo the contribution modeling using
2012 base case emission inventories that
are revised based on proposed rule
comments. Several commenters also
asked that EPA update the contribution
modeling analyses using the latest
version of CAMx.
Response: In response to these
comments, we have rerun our source
apportionment modeling for PM2.5 and
ozone for the 2012 base case using the
updated emission inventories described
above in section V.C.1 and the latest
version of CAMx, version 5.30.
The states EPA analyzed for interstate
contributions for ozone and for PM2.5 for
the final rule are: Alabama, Arkansas,
Connecticut, Delaware, Florida, Georgia,
Illinois, Indiana, Iowa, Kansas,
Kentucky, Louisiana, Maine,
Maryland,31 Massachusetts, Michigan,
Minnesota, Mississippi, Missouri,
Nebraska, New Hampshire, New Jersey,
New York, North Carolina, North
Dakota, Ohio, Oklahoma, Pennsylvania,
Rhode Island, South Carolina, South
Dakota, Tennessee, Texas, Vermont,
Virginia, West Virginia, and
Wisconsin.32 These are the same states
that EPA analyzed for the proposed rule.
For the proposed rule, we used a
relative approach for calculating the
contributions to downwind
nonattainment and maintenance
receptors from the outputs of the source
apportionment modeling. As part of this
approach, the source apportionment
predictions are combined with
measurement-based concentrations to
calculate the contributions from each
state to nonattainment and/or
maintenance receptors. This is similar
to the approach used to calculate future
year design values, as described in
section V.C.2.
Comment: One commenter said that
using the source apportionment
modeling predictions in a relative sense
strengthens the determination of
contributions and addresses an
important source of uncertainty. There
were no comments that suggested an
alternative approach.
31 As in the proposal, EPA has combined the
contributions from Maryland and the District of
Columbia as a single entity in our contribution
analysis for the final rule. EPA believes that this is
a fair representation of emissions for transport
analysis because of the small size of the District of
Columbia and its close proximity to Maryland.
However, the District of Columbia is not included
in the Transport Rule due to the significant
contribution analysis findings in section VI.D.
32 There were also several other states that are
only partially contained within the 12 km modeling
domain (i.e., Colorado, Montana, New Mexico, and
Wyoming). However, EPA did not individually
track the emissions or assess the contribution from
emissions in these states.
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48239
Response: For the final Transport
Rule we are applying the relative
approach developed for the proposed
rule to calculate contributions from each
state to downwind nonattainment and
maintenance receptors.
As noted above, for the final rule we
modeled the updated 2012 base case
emissions using CAMX v5.30 to
determine the contributions from
emissions in upwind states to
nonattainment and maintenance sites in
downwind states. Contributions to
nonattainment and maintenance
receptors are evaluated independently
for each state to determine if the
contributions are at or above the
threshold criteria.
For each upwind state, the maximum
contribution to nonattainment is
calculated based on the single largest
contribution to a future year (2012)
downwind nonattainment receptor. The
maximum contribution to maintenance
is calculated based on the single largest
contribution to a future year (2012)
downwind maintenance receptor. Since
the contributions are calculated
independently for each receptor, the
upwind contribution to maintenance
can sometimes be larger than the
contribution to nonattainment, and vice
versa. This also means that maximum
contributions to nonattainment can be
below the threshold while maximum
contributions to maintenance may be at
or above the threshold, or vice versa.
V.D.2.a. Estimated Interstate
Contributions to Annual PM2.5 and
24-Hour PM2.5
In this section, we present the
interstate contributions from emissions
in upwind states to downwind
nonattainment and maintenance sites
for the annual PM2.5 NAAQS and the 24hour PM2.5 NAAQS based on modeling
updated for the final rule. As described
previously in section V.D.1, states
which contribute 0.15 μg/m3 or more to
annual PM2.5 nonattainment or
maintenance in another state are
identified as states with contributions
large enough to warrant further analysis.
For 24-hour PM2.5, states which
contribute 0.35 μg/m 3 or more to
24-hour PM2.5 nonattainment or
maintenance in another state are
identified as states with contributions to
downwind nonattainment and
maintenance sites large enough to
warrant further analysis.
For annual PM2.5, we calculated each
state’s contribution to each of the 12
monitoring sites that are projected to be
nonattainment and each of the 4 sites
that are projected to have maintenance
problems for the annual PM2.5 NAAQS
in the 2012 base case. A detailed
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48240
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description of the calculations can be
found in the Air Quality Modeling Final
Rule TSD. The largest contribution from
each state to annual PM2.5
nonattainment in downwind sites is
provided in Table V.D–1. The Largest
Contribution from Each State to Annual
PM2.5 maintenance in downwind sites is
also provided in Table V.D–1. The
contributions from each state to all
projected 2012 nonattainment and
maintenance sites for the annual PM2.5
NAAQS are provided in the Air Quality
Modeling Final Rule TSD.
TABLE V.D–1—LARGEST CONTRIBUTION TO DOWNWIND ANNUAL PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE FOR
EACH OF 37 STATES
Largest downwind
contribution to nonattainment for annual PM2.5 (μg/m3)
Upwind state
Alabama ...................................................................................................................................................
Arkansas ..................................................................................................................................................
Connecticut ..............................................................................................................................................
Delaware ..................................................................................................................................................
Florida ......................................................................................................................................................
Georgia ....................................................................................................................................................
Illinois .......................................................................................................................................................
Indiana .....................................................................................................................................................
Iowa .........................................................................................................................................................
Kansas .....................................................................................................................................................
Kentucky ..................................................................................................................................................
Louisiana ..................................................................................................................................................
Maine .......................................................................................................................................................
Maryland ..................................................................................................................................................
Massachusetts .........................................................................................................................................
Michigan ...................................................................................................................................................
Minnesota ................................................................................................................................................
Mississippi ................................................................................................................................................
Missouri ....................................................................................................................................................
Nebraska ..................................................................................................................................................
New Hampshire .......................................................................................................................................
New Jersey ..............................................................................................................................................
New York .................................................................................................................................................
North Carolina ..........................................................................................................................................
North Dakota ............................................................................................................................................
Ohio .........................................................................................................................................................
Oklahoma .................................................................................................................................................
Pennsylvania ............................................................................................................................................
Rhode Island ............................................................................................................................................
South Carolina .........................................................................................................................................
South Dakota ...........................................................................................................................................
Tennessee ...............................................................................................................................................
Texas .......................................................................................................................................................
Vermont ...................................................................................................................................................
Virginia .....................................................................................................................................................
West Virginia ............................................................................................................................................
Wisconsin .................................................................................................................................................
Largest downwind
contribution to
maintenance
for annual PM2.5
(μg/m3)
0.51
0.10
0.00
0.00
0.08
0.46
0.50
1.34
0.26
0.09
0.94
0.09
0.00
0.15
0.00
0.64
0.14
0.05
1.22
0.06
0.00
0.02
0.21
0.20
0.06
1.34
0.08
0.54
0.00
0.24
0.03
0.32
0.18
0.00
0.12
0.95
0.22
0.19
0.04
0.00
0.00
0.01
0.13
0.65
1.27
0.14
0.04
0.81
0.03
0.00
0.06
0.00
0.64
0.09
0.01
0.27
0.03
0.00
0.01
0.21
0.06
0.04
0.94
0.03
0.54
0.00
0.04
0.01
0.32
0.07
0.00
0.06
0.40
0.19
ebenthall on DSK6TPTVN1PROD with RULES2
Based on the state-by-state
contribution analysis, there are 18
states 33 which contribute 0.15 μg/m3 or
more to downwind annual PM2.5
nonattainment. These states are:
Alabama, Georgia, Illinois, Indiana,
Iowa, Kentucky, Maryland, Michigan,
Missouri, New York, North Carolina,
Ohio, Pennsylvania, South Carolina,
Tennessee, Texas, West Virginia, and
Wisconsin. In Table V.D–2, we provide
a list of the downwind nonattainment
sites to which each upwind state
contributes 0.15 μg/m3 or more (i.e., the
upwind state to downwind
nonattainment ‘‘linkages’’).
There are 12 states which contribute
0.15 μg/m3 or more to downwind
annual PM2.5 maintenance. These states
are: Alabama, Illinois, Indiana,
Kentucky, Michigan, Missouri, New
York, Ohio, Pennsylvania, Tennessee,
West Virginia, and Wisconsin. In Table
V.D–3, we provide a list of the
downwind maintenance sites to which
each upwind state contributes 0.15 μg/
m3 or more (i.e., the upwind state to
downwind maintenance ‘‘linkages’’).
33 As in the proposal, EPA has combined the
contributions from Maryland and the District of
Columbia as a single entity in our contribution
analysis for the final rule. EPA believes that this is
a fair representation of emissions for transport
analysis because of the small size of the District of
Columbia and its close proximity to Maryland.
However, the District of Columbia is not included
in the Transport Rule due to the significant
contribution analysis findings in section VI.D.
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48241
TABLE V.D–2—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR ANNUAL PM2.5
Upwind state
Alabama ................
Georgia .................
Illinois ....................
Indiana ..................
Iowa ......................
Kentucky ...............
Maryland ...............
Michigan ................
Missouri .................
New York ..............
North Carolina .......
Ohio ......................
Pennsylvania .........
South Carolina ......
Tennessee ............
Texas ....................
West Virginia .........
Wisconsin ..............
Downwind receptor sites
Fulton, GA (131210039) ......
Jefferson, AL (10730023) ....
Jefferson, AL (10732003) ....
Cuyahoga, OH (390350045)
Hamilton, OH (390618001) ..
Jefferson, AL (10730023) ....
Wayne, MI (261630033) ......
Hamilton, OH (390610014) ..
Madison, IL (171191007).
Jefferson, AL (10730023) ....
Wayne, MI (261630033) ......
Hamilton, OH (390610014) ..
Allegheny, PA (420030064).
Madison, IL (171191007) .....
Hamilton, OH (390610014) ..
Madison, IL (171191007) .....
Hamilton, OH (390610014) ..
Cuyahoga, OH (390350038)
Fulton, GA (131210039).
Jefferson, AL (10730023) ....
Wayne, MI (261630033) ......
Fulton, GA (131210039) ......
Cuyahoga, OH (390350060)
Fulton, GA (131210039).
Jefferson, AL (10730023) ....
Hamilton, OH (390610014) ..
Madison, IL (171191007).
Fulton, GA (131210039) ......
Cuyahoga, OH (390350060)
Allegheny, PA (420030064).
Madison, IL (171191007) .....
Cuyahoga, OH (390350060)
Hamilton, OH (390610014) ..
Jefferson, AL (10732003).
Fulton, GA (131210039) ......
Cuyahoga, OH (390350060)
Allegheny, PA (420030064).
Jefferson, AL (10732003) ....
Cuyahoga, OH (390350038)
Hamilton, OH (390610042) ..
Hamilton, OH (390610042) ..
Hamilton, OH (390618001).
Wayne, MI (261630033) ......
Hamilton, OH (390610014) ..
Cuyahoga, OH (390350038).
Hamilton, OH (390610042).
Fulton, GA (131210039) ......
Cuyahoga, OH (390350045)
Hamilton, OH (390618001) ..
Madison, IL (171191007).
Cuyahoga, OH (390350060).
Allegheny, PA (420030064).
Jefferson, AL (10732003) ....
Cuyahoga, OH (390350038)
Hamilton, OH (390610042) ..
Fulton, GA (131210039) ......
Cuyahoga, OH (390350045)
Hamilton, OH (390618001) ..
Madison, IL (171191007).
Cuyahoga, OH (390350060).
Allegheny, PA (420030064).
Cuyahoga, OH (390350038)
Hamilton, OH (390610042) ..
Cuyahoga, OH (390350038)
Hamilton, OH (390610042) ..
Cuyahoga, OH (390350045)
Cuyahoga, OH (390350045)
Hamilton, OH (390618001) ..
Cuyahoga, OH (390350045)
Hamilton, OH (390618001).
Cuyahoga, OH (390350060)
Cuyahoga, OH (390350060).
Allegheny, PA (420030064).
Cuyahoga, OH (390350060).
Jefferson, AL (10732003) ....
Allegheny, PA (420030064).
Wayne, MI (261630033) ......
Hamilton, OH (390610014) ..
Fulton, GA (131210039) ......
Madison, IL (171191007).
Cuyahoga, OH (390350038)
Hamilton, OH (390610042) ..
Cuyahoga, OH (390350045).
Hamilton, OH (390618001).
Jefferson, AL (10732003) ....
Hamilton, OH (390610042) ..
Fulton, GA (131210039) ......
Hamilton, OH (390618001).
Madison, IL (171191007).
Wayne, MI (261630033) ......
Hamilton, OH (390610014) ..
Cuyahoga, OH (390350038)
Hamilton, OH (390610042) ..
Cuyahoga, OH (390350045).
Hamilton, OH (390618001).
Wayne, MI (261630033) ......
Hamilton, OH (390610014) ..
Cuyahoga, OH (390350038)
Hamilton, OH (390618001).
Cuyahoga, OH (390350045)
Allegheny, PA (420030064).
TABLE V.D–3—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR ANNUAL PM2.5
Upwind state
Alabama ................
Illinois ....................
Indiana ..................
Kentucky ...............
Michigan ................
Missouri .................
New York ..............
Ohio ......................
Pennsylvania .........
Tennessee ............
West Virginia .........
Wisconsin ..............
Downwind receptor sites
Marion, IN (180970081) .......
Marion, IN (180970081) .......
Cuyahoga, OH (390350065)
Marion, IN (180970081) .......
Marion, IN (180970081) .......
Marion, IN (180970081) .......
Cuyahoga, OH (390350065).
Marion, IN (180970081) .......
Marion, IN (180970081) .......
Marion, IN (180970081) .......
Marion, IN (180970081) .......
Marion, IN (180970081) .......
ebenthall on DSK6TPTVN1PROD with RULES2
For 24-hour PM2.5, we calculated each
state’s contribution to each of the 20
monitoring sites that are projected to be
nonattainment and each of the 21 sites
that are projected to have maintenance
problems for the 24-hour PM2.5 NAAQS
in the 2012 base case. A detailed
Marion, IN (180970083) .......
Marion, IN (180970083) .......
Hamilton, OH (390617001).
Marion, IN (180970083) .......
Marion, IN (180970083) .......
Marion, IN (180970083) .......
Marion,
Marion,
Marion,
Marion,
Marion,
IN
IN
IN
IN
IN
(180970083).
(180970083) .......
(180970083) .......
(180970083) .......
(180970083) .......
Hamilton, OH (390617001).
Cuyahoga, OH (390350065)
Hamilton, OH (390617001).
Cuyahoga, OH (390350065)
Cuyahoga, OH (390350065)
Cuyahoga, OH (390350065)
Hamilton, OH (390617001).
Hamilton, OH (390617001).
Hamilton, OH (390617001).
Cuyahoga, OH (390350065)
Hamilton, OH (390617001).
Cuyahoga, OH (390350065)
Cuyahoga, OH (390350065)
Hamilton, OH (390617001).
description of the calculations can be
found in the Air Quality Modeling Final
Rule TSD. The largest contribution from
each state to 24-hour PM2.5
nonattainment in downwind sites is
provided in Table V.D–4. The largest
contribution from each state to 24-hour
Hamilton, OH (390617001).
Hamilton, OH (390617001).
PM2.5 maintenance in downwind sites is
also provided in Table V.D–4. The
contributions from each state to all
projected 2012 nonattainment and
maintenance sites for the 24-hour PM2.5
NAAQS are provided in the Air Quality
Modeling Final Rule TSD.
TABLE V.D–4—LARGEST CONTRIBUTION TO DOWNWIND 24-HOUR PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE FOR
EACH OF 37 STATES
Largest downwind
contribution to nonattainment for 24hour PM2.5 (μg/m3)
Upwind state
Alabama ...................................................................................................................................................
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0.51
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Largest downwind
contribution to
maintenance for
24-hour PM2.5
(μg/m3)
0.42
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TABLE V.D–4—LARGEST CONTRIBUTION TO DOWNWIND 24-HOUR PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE FOR
EACH OF 37 STATES—Continued
Largest downwind
contribution to nonattainment for 24hour PM2.5 (μg/m3)
Upwind state
Arkansas ..................................................................................................................................................
Connecticut ..............................................................................................................................................
Delaware ..................................................................................................................................................
Florida ......................................................................................................................................................
Georgia ....................................................................................................................................................
Illinois .......................................................................................................................................................
Indiana .....................................................................................................................................................
Iowa .........................................................................................................................................................
Kansas .....................................................................................................................................................
Kentucky ..................................................................................................................................................
Louisiana ..................................................................................................................................................
Maine .......................................................................................................................................................
Maryland ..................................................................................................................................................
Massachusetts .........................................................................................................................................
Michigan ...................................................................................................................................................
Minnesota ................................................................................................................................................
Mississippi ................................................................................................................................................
Missouri ....................................................................................................................................................
Nebraska ..................................................................................................................................................
New Hampshire .......................................................................................................................................
New Jersey ..............................................................................................................................................
New York .................................................................................................................................................
North Carolina ..........................................................................................................................................
North Dakota ............................................................................................................................................
Ohio .........................................................................................................................................................
Oklahoma .................................................................................................................................................
Pennsylvania ............................................................................................................................................
Rhode Island ............................................................................................................................................
South Carolina .........................................................................................................................................
South Dakota ...........................................................................................................................................
Tennessee ...............................................................................................................................................
Texas .......................................................................................................................................................
Vermont ...................................................................................................................................................
Virginia .....................................................................................................................................................
West Virginia ............................................................................................................................................
Wisconsin .................................................................................................................................................
Based on the state-by-state
contribution analysis, there are 21
states 34 which contribute 0.35 μg/m3 or
more to downwind 24-hour PM2.5
nonattainment. These states are:
Alabama, Georgia, Illinois, Indiana,
Iowa, Kansas, Kentucky, Maryland,
Michigan, Minnesota, Missouri, New
Jersey, New York, North Carolina, Ohio,
Pennsylvania, Tennessee, Texas,
Virginia, West Virginia, and Wisconsin.
In Table V.D–5, we provide a list of the
downwind nonattainment counties to
which each upwind state contributes
0.35 μg/m3 or more (i.e., the upwind
state to downwind nonattainment
‘‘linkages’’).
There are 21 states which contribute
0.35 μg/m3 or more to downwind 24hour PM2.5 maintenance. These states
are: Alabama, Georgia, Illinois, Indiana,
Iowa, Kansas, Kentucky, Maryland,
Largest downwind
contribution to
maintenance for
24-hour PM2.5
(μg/m3)
0.24
0.10
0.22
0.07
1.10
3.72
3.56
0.82
0.37
4.38
0.11
0.06
2.83
0.19
1.86
0.61
0.06
3.73
0.24
0.05
0.68
0.83
0.40
0.21
5.85
0.17
2.85
0.02
0.29
0.10
1.38
0.37
0.03
1.21
4.02
0.69
0.23
0.18
0.20
0.03
0.92
5.70
5.15
1.55
0.81
3.58
0.13
0.10
2.11
0.30
2.03
1.01
0.07
3.71
0.52
0.10
0.75
1.34
0.38
0.33
4.74
0.20
2.29
0.03
0.25
0.17
1.30
0.33
0.05
1.01
3.33
0.97
Michigan, Minnesota, Missouri,
Nebraska, New Jersey, New York, North
Carolina, Ohio, Pennsylvania,
Tennessee, Virginia, West Virginia, and
Wisconsin. In Table V.D–6, we provide
a list of the downwind maintenance
sites to which each upwind state
contributes 0.35 μg/m3 or more (i.e., the
upwind state to downwind maintenance
‘‘linkages’’).
TABLE V.D–5—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5
ebenthall on DSK6TPTVN1PROD with RULES2
Upwind state
Alabama ................
Georgia .................
Illinois ....................
Downwind receptor sites
Marion, IN (180970043) .......
Jefferson, AL (10730023).
Marion, IN (180970043) .......
Wayne, MI (261630015) ......
Cuyahoga, OH (390350038)
Allegheny, PA (420030116)
34 As in the proposal, EPA has combined the
contributions from Maryland and the District of
Columbia as a single entity in our contribution
analysis for the final rule. EPA believes that this is
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Marion, IN (180970066) .......
Marion, IN (180970081).
Marion, IN (180970066) .......
Wayne, MI (261630016) ......
Cuyahoga, OH (390350060)
Beaver, PA (420070014) .....
Marion, IN (180970081) .......
Wayne, MI (261630019) ......
Allegheny, PA (420030064)
Brooke, WV (540090011) ....
a fair representation of emissions for transport
analysis because of the small size of the District of
Columbia and its close proximity to Maryland.
However, the District of Columbia is not included
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St Clair, MI (261470005).
Wayne, MI (261630033).
Allegheny, PA (420030093).
Milwaukee, WI (550790043).
in the Transport Rule due to the significant
contribution analysis findings in section VI.D.
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48243
TABLE V.D–5—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued
Indiana ..................
Iowa ......................
Kansas ..................
Kentucky ...............
Maryland ...............
Michigan ................
Minnesota .............
Missouri .................
New Jersey ...........
New York ..............
North Carolina .......
Ohio ......................
Pennsylvania .........
Tennessee ............
Texas ....................
Virginia ..................
West Virginia .........
Wisconsin ..............
Jefferson, AL (10730023) ....
Wayne, MI (261630015) ......
Cuyahoga, OH (390350038)
Allegheny, PA (420030116)
Cook, IL (170311016) ..........
Madison, IL (171191007).
Jefferson, AL (10730023) ....
Marion, IN (180970066) .......
Wayne, MI (261630016) ......
Cuyahoga, OH (390350060)
Beaver, PA (420070014) .....
Cuyahoga, OH (390350038)
Cook, IL (170311016) ..........
Allegheny, PA (420030064)
Milwaukee, WI (550790043).
Milwaukee, WI (550790043).
Cook, IL (170311016) ..........
Marion, IN (180970081) .......
Allegheny, PA (420030116)
Lancaster, PA (420710007).
St Clair, MI (261470005) ......
Cuyahoga, OH (390350060)
Lancaster, PA (420710007).
Jefferson, AL (10730023) ....
Marion, IN (180970066) .......
Wayne, MI (261630016) ......
Allegheny, PA (420030093)
Brooke, WV (540090011) ....
Jefferson, AL (10730023) ....
Marion, IN (180970066) .......
Wayne, MI (261630016) ......
Cuyahoga, OH (390350060)
Jefferson, AL (10730023) ....
Marion, IN (180970081) .......
Cuyahoga, OH (390350038)
Madison, IL (171191007).
Lancaster, PA (420710007).
Jefferson, AL (10730023) ....
Marion, IN (180970066) .......
Wayne, MI (261630016) ......
Cuyahoga, OH (390350060)
Beaver, PA (420070014) .....
Cook, IL (170311016) ..........
Cook, IL (170311016) ..........
Wayne, MI (261630016) ......
Cuyahoga, OH (390350060)
Beaver, PA (420070014) .....
Madison, IL (171191007) .....
Madison, IL (171191007) .....
Wayne, MI (261630019) ......
Allegheny, PA (420030064)
Brooke, WV (540090011) ....
Milwaukee, WI (550790043).
St Clair, MI (261470005).
Wayne, MI (261630033).
Allegheny, PA (420030093).
Milwaukee, WI (550790043).
Cook, IL (170311016) ..........
Marion, IN (180970081) .......
Wayne, MI (261630019) ......
Allegheny, PA (420030064)
Brooke, WV (540090011) ....
Lancaster, PA (420710007).
Madison, IL (171191007) .....
Allegheny, PA (420030093)
Madison, IL (171191007) .....
St Clair, MI (261470005) ......
Wayne, MI (261630033) ......
Allegheny, PA (420030093)
Milwaukee, WI (550790043).
Marion, IN (180970043).
Wayne, MI (261630015).
Cuyahoga, OH (390350038).
Allegheny, PA (420030116).
Cuyahoga, OH (390350038)
Beaver, PA (420070014) .....
Cuyahoga, OH (390350060).
Brooke, WV (540090011).
Madison, IL (171191007) .....
St Clair, MI (261470005) ......
Beaver, PA (420070014) .....
Marion, IN (180970043) .......
Wayne, MI (261630015) ......
Milwaukee, WI (550790043).
Marion, IN (180970066).
Allegheny, PA (420030064).
Wayne, MI (261630016) ......
Lancaster, PA (420710007).
Wayne, MI (261630019) ......
Wayne, MI (261630033).
Cook, IL (170311016) ..........
Marion, IN (180970081) .......
Wayne, MI (261630019) ......
Allegheny, PA (420030116)
Milwaukee, WI (550790043).
Cook, IL (170311016) ..........
Marion, IN (180970081) .......
Wayne, MI (261630019) ......
Brooke, WV (540090011) ....
Madison, IL (171191007) .....
St Clair, MI (261470005) ......
Allegheny, PA (420030116).
Madison, IL (171191007) .....
St Clair, MI (261470005) ......
Wayne, MI (261630033) ......
Beaver, PA (420070014) .....
Marion, IN (180970043).
Wayne, MI (261630015)
Allegheny, PA (420030064).
Lancaster, PA (420710007).
Madison, IL (171191007) .....
St Clair, MI (261470005) ......
Wayne, MI (261630033) ......
Milwaukee, WI (550790043)..
Marion, IN (180970043) .......
Wayne, MI (261630015) ......
Marion, IN (180970043).
Wayne, MI (261630015).
Cuyahoga, OH (390350038).
Cook, IL (170311016) ..........
Marion, IN (180970081) .......
Wayne, MI (261630019) ......
Allegheny, PA (420030064)
Lancaster, PA (420710007)
Wayne, MI (261630019) ......
Madison, IL (171191007) .....
St Clair, MI (261470005) ......
Wayne, MI (261630033) ......
Allegheny, PA (420030093)
Milwaukee, WI (550790043).
Wayne, MI (261630033).
Marion, IN (180970043).
Wayne, MI (261630015).
Cuyahoga, OH (390350038).
Allegheny, PA (420030116).
Marion, IN (180970066).
Wayne, MI (261630033).
TABLE V.D–6—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5
Upwind state
Downwind receptor sites
Alabama ................
Washtenaw, MI (261610008)
Georgia .................
Illinois ....................
Jefferson, AL (10732003).
Lake, IN (180890022) ..........
Cuyahoga, OH (390350045)
Montgomery, OH
(391130032).
York, PA (421330008) .........
Jefferson, AL (10732003) ....
Cook, IL (170316005) ..........
Cuyahoga, OH (390350045)
Montgomery, OH
(391130032).
York, PA (421330008) .........
Cook, IL (170310052) ..........
Madison, IL (171190023) .....
Milwaukee, WI (550790026).
Cook, IL (170310052) ..........
Jefferson, AL (10732003) ....
Cook, IL (170316005) ..........
Washtenaw, MI (261610008)
Hamilton, OH (390618001) ..
Indiana ..................
ebenthall on DSK6TPTVN1PROD with RULES2
Iowa ......................
Kansas ..................
Kentucky ...............
Allegheny, PA (420031301)
Milwaukee, WI (550790026).
VerDate Mar<15>2010
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Jkt 223001
PO 00000
Butler, OH (390170003) .......
Montgomery, OH
(391130032).
Lake, IN (180890026) ..........
Cuyahoga, OH (390350065)
Allegheny, PA (420031008)
Washtenaw, MI (261610008)
Hamilton, OH (390618001) ..
Allegheny, PA (420031301)
Butler, OH (390170003).
Jefferson, OH (390811001).
Allegheny, PA (420033007).
Milwaukee, WI (550790010)
Cook, IL (170310052) ..........
Madison, IL (171190023) .....
Cuyahoga, OH (390350065)
Allegheny, PA (420031008)
Milwaukee, WI (550790026).
Cook, IL (170312001) ..........
Washtenaw, MI (261610008)
Hamilton, OH (390618001) ..
Allegheny, PA (420031301)
Cook, IL (170313301).
Butler, OH (390170003).
Jefferson, OH (390811001).
Allegheny, PA (420033007).
Milwaukee, WI (550790010)
Cook, IL (170312001) ..........
Lake, IN (180890022) ..........
Milwaukee, WI (550790026).
Cook, IL (170313301) ..........
Lake, IN (180890026) ..........
Cook, IL (170316005).
Milwaukee, WI (550790010).
Cook, IL (170316005) ..........
Cook, IL (170310052) ..........
Madison, IL (171190023) .....
Butler, OH (390170003) .......
Jefferson, OH (390811001)
Allegheny, PA (420033007)
Milwaukee, WI (550790010)
Cook, IL (170312001) ..........
Lake, IN (180890022) ..........
Cuyahoga, OH (390350045)
Montgomery, OH
(391130032).
York, PA (421330008) .........
Frm 00037
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Fmt 4701
Sfmt 4700
08AUR2
Milwaukee, WI (550790026).
Cook, IL (170313301).
Lake, IN (180890026).
Cuyahoga, OH (390350065).
Allegheny, PA (420031008).
Milwaukee, WI (550790010).
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TABLE V.D–6—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued
Maryland ...............
Michigan ................
Nebraska ...............
New Jersey ...........
New York ..............
North Carolina .......
Ohio ......................
Pennsylvania .........
Cook, IL (170312001) ..........
Lake, IN (180890022) ..........
Cuyahoga, OH (390350065)
Allegheny, PA (420031008)
Cook, IL (170313301) ..........
Lake, IN (180890026) ..........
Hamilton, OH (390618001) ..
Allegheny, PA (420031301)
Milwaukee, WI (550790010)
Milwaukee, WI (550790026).
Cook, IL (170312001) ..........
Lake, IN (180890022) ..........
Milwaukee, WI (550790026).
Butler, OH (390170003) .......
Minnesota .............
Missouri .................
York, PA (421330008).
Cook, IL (170310052) ..........
Madison, IL (171190023) .....
Cuyahoga, OH (390350045)
Montgomery, OH
(391130032).
York, PA (421330008) .........
Milwaukee, WI (550790010)
Cook, IL (170310052) ..........
Madison, IL (171190023) .....
Hamilton, OH (390618001) ..
Montgomery, OH
(391130032).
Milwaukee, WI (550790010)
Milwaukee, WI (550790010)
York, PA (421330008).
Washtenaw, MI (261610008)
York, PA (421330008).
Jefferson, AL (10732003) ....
Cook, IL (170316005) ..........
Washtenaw, MI (261610008)
York, PA (421330008) .........
Jefferson, AL (10732003) ....
Madison, IL (171190023) .....
Milwaukee, WI (550790026).
Milwaukee, WI (550790026).
Butler, OH (390170003) .......
Jefferson, OH (390811001)
Cook, IL (170313301) ..........
Lake, IN (180890026) ..........
Cook, IL (170316005).
Butler, OH (390170003).
Jefferson, OH (390811001).
Allegheny, PA (420033007).
Cook, IL (170316005).
Washtenaw, MI
(261610008).
Allegheny, PA (420031008).
Cuyahoga, OH (390350045)
Cuyahoga, OH (390350065)
York, PA (421330008).
Cook, IL (170310052) ..........
Madison, IL (171190023) .....
Allegheny, PA (420031008)
Milwaukee, WI (550790010)
Cook, IL (170310052) ..........
Lake, IN (180890022) ..........
Cook, IL (170312001) ..........
Lake, IN (180890022) ..........
Allegheny, PA (420031301)
Milwaukee, WI (550790026).
Cook, IL (170312001) ..........
Lake, IN (180890026) ..........
Cook, IL (170313301).
Lake, IN (180890026).
Allegheny, PA (420033007).
Cuyahoga, OH (390350065)
Milwaukee, WI (550790010)
Washtenaw, MI (261610008)
Montgomery, OH
(391130032).
Butler, OH (390170003).
Cook, IL (170313301).
Washtenaw, MI
(261610008).
Hamilton, OH (390618001).
Milwaukee, WI (550790026).
Tennessee ............
Jefferson, AL (10732003) ....
Cuyahoga, OH (390350065)
Cuyahoga, OH (390350045)
Montgomery, OH
(391130032).
Madison, IL (171190023) .....
Hamilton, OH (390618001) ..
Virginia ..................
West Virginia .........
York, PA (421330008).
Jefferson, AL (10732003) ....
Madison, IL (171190023) .....
Cook, IL (170310052) ..........
Lake, IN (180890022) ..........
Cook, IL (170312001) ..........
Lake, IN (180890026) ..........
Cuyahoga, OH (390350045)
Montgomery, OH
(391130032).
York, PA (421330008) .........
Cook, IL (170312001) ..........
Lake, IN (180890026).
Cuyahoga, OH (390350065)
Allegheny, PA (420031008)
Cook, IL (170313301).
Washtenaw, MI
(261610008).
Hamilton, OH (390618001).
Allegheny, PA (420031301).
Milwaukee, WI (550790010).
Cook, IL (170313301) ..........
Cook, IL (170316005).
Butler, OH (390170003) .......
Jefferson, OH (390811001)
Wisconsin ..............
Allegheny, PA (420033007)
Cook, IL (170310052) ..........
Lake, IN (180890022) ..........
b. Estimated Interstate Contributions to
8-Hour Ozone
In this section, we present the
interstate contributions from emissions
in upwind states to downwind
nonattainment and maintenance sites
for the ozone NAAQS. As described
previously in section V.D.1, states
which contribute 0.8 ppb or more to
8-hour ozone nonattainment or
maintenance in another state are
identified as states with contributions to
downwind attainment and maintenance
sites large enough to warrant further
analysis.
We calculated each state’s
contribution to ozone at each of the 4
monitoring sites that are projected to be
nonattainment and each of 6 35 sites that
are projected to have maintenance
problems for the 8-hour ozone NAAQS
in the 2012 base case. A detailed
description of the calculations can be
found in the Air Quality Modeling Final
Rule TSD. The largest contribution from
each state to 8-hour ozone
nonattainment in downwind sites is
provided in Table V.D–7. The largest
contribution from each state to 8-hour
ozone maintenance in downwind sites
is also provided in Table V.D.2–7. The
contributions from each state to all
projected 2012 nonattainment and
maintenance sites for the 8-hour ozone
NAAQS are provided in the Air Quality
Modeling Final Rule TSD.
TABLE V.D–7—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE FOR EACH
OF 37 STATES
Largest downwind
contribution to
nonattainment for
ozone
(ppb)
ebenthall on DSK6TPTVN1PROD with RULES2
Upwind state
Alabama ...................................................................................................................................................
Arkansas ..................................................................................................................................................
35 There are 6 additional sites with projected 2012
nonattainment or maintenance (Harris Co., Texas
sites 482010024, 482010062, 482010066,
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482011015, 482011035, and 482011039) for which
there are less than 5 days with 8-hour ozone
PO 00000
Frm 00038
Fmt 4701
Sfmt 4700
Largest downwind
contribution to
maintenance for
ozone
(ppb)
4.0
2.1
predictions of at least 70 ppb. Thus, we did not
calculate contributions for these 6 sites.
E:\FR\FM\08AUR2.SGM
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2.8
2.0
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48245
TABLE V.D–7—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE FOR EACH
OF 37 STATES—Continued
Largest downwind
contribution to
nonattainment for
ozone
(ppb)
Upwind state
Connecticut ..............................................................................................................................................
Delaware ..................................................................................................................................................
Florida ......................................................................................................................................................
Georgia ....................................................................................................................................................
Illinois .......................................................................................................................................................
Indiana .....................................................................................................................................................
Iowa .........................................................................................................................................................
Kansas .....................................................................................................................................................
Kentucky ..................................................................................................................................................
Louisiana ..................................................................................................................................................
Maine .......................................................................................................................................................
Maryland ..................................................................................................................................................
Massachusetts .........................................................................................................................................
Michigan ...................................................................................................................................................
Minnesota ................................................................................................................................................
Mississippi ................................................................................................................................................
Missouri ....................................................................................................................................................
Nebraska ..................................................................................................................................................
New Hampshire .......................................................................................................................................
New Jersey ..............................................................................................................................................
New York .................................................................................................................................................
North Carolina ..........................................................................................................................................
North Dakota ............................................................................................................................................
Ohio .........................................................................................................................................................
Oklahoma .................................................................................................................................................
Pennsylvania ............................................................................................................................................
Rhode Island ............................................................................................................................................
South Carolina .........................................................................................................................................
South Dakota ...........................................................................................................................................
Tennessee ...............................................................................................................................................
Texas .......................................................................................................................................................
Vermont ...................................................................................................................................................
Virginia .....................................................................................................................................................
West Virginia ............................................................................................................................................
Wisconsin .................................................................................................................................................
Based on the state-by-state
contribution analysis, there are 11 states
that contribute 0.8 ppb or more to
downwind 8-hour ozone nonattainment.
These states are: Alabama, Arkansas,
Georgia, Illinois, Indiana, Kentucky,
Louisiana, Mississippi, Missouri,
Tennessee, and Texas.36 In Table V.D–
8, we provide a list of the downwind
nonattainment counties to which each
discussed in section III, EPA is issuing a
supplemental notice of proposed rulemaking to
provide an opportunity for public comment on our
conclusion that emissions from Iowa, Kansas,
Michigan, Missouri, Oklahoma, and Wisconsin
significantly contribute to nonattainment or
interfere with maintenance of the 1997 ozone
NAAQS in other states.
ebenthall on DSK6TPTVN1PROD with RULES2
36 As
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Jkt 223001
upwind state contributes 0.8 ppb or
more (i.e., the upwind state to
downwind nonattainment ‘‘linkages’’).
There are 26 states 37 which
contribute 0.8 ppb or more to
downwind 8-hour ozone maintenance.
These states are: Alabama, Arkansas,
Florida, Georgia, Illinois, Indiana, Iowa,
Kansas, Kentucky, Louisiana, Maryland,
37 As in the proposal, EPA has combined the
contributions from Maryland and the District of
Columbia as a single entity in our contribution
analysis for the final rule. EPA believes that this is
a fair representation of emissions for transport
analysis because of the small size of the District of
Columbia and its close proximity to Maryland.
However, the District of Columbia is not included
in the Transport Rule due to the significant
contribution analysis findings in section VI.D.
PO 00000
Frm 00039
Fmt 4701
Sfmt 4700
0.0
0.0
0.5
1.6
1.9
1.3
0.6
0.5
1.6
8.0
0.0
0.0
0.0
0.0
0.3
4.0
1.1
0.2
0.0
0.0
0.0
0.5
0.2
0.1
0.3
0.1
0.0
0.4
0.1
2.2
3.9
0.0
0.2
0.0
0.2
Largest downwind
contribution to
maintenance for
ozone
(ppb)
0.2
0.6
3.6
2.8
26.8
9.4
0.9
1.0
1.6
11.1
0.0
2.7
0.6
0.9
0.2
3.3
4.8
0.2
0.1
11.5
18.8
1.3
0.1
3.2
2.8
8.2
0.0
0.9
0.1
1.1
1.9
0.0
8.2
2.8
2.2
Michigan, Mississippi, Missouri, New
Jersey, New York, North Carolina, Ohio,
Oklahoma, Pennsylvania, South
Carolina, Tennessee, Texas, Virginia,
West Virginia, and Wisconsin.38 In
Table V.D.2–9, we provide a list of the
downwind nonattainment counties to
which each upwind state contributes 0.8
ppb or more (i.e., the upwind state to
downwind nonattainment ‘‘linkages’’).
38 As discussed in section III, EPA is issuing a
supplemental notice of proposed rulemaking to
provide an opportunity for public comment on our
conclusion that emissions from Iowa, Kansas,
Michigan, Missouri, Oklahoma, and Wisconsin
significantly contribute to nonattainment or
interfere with maintenance of the 1997 ozone
NAAQS in other states.
E:\FR\FM\08AUR2.SGM
08AUR2
48246
Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
TABLE V.D–8—UPWIND STATE TO DOWNWIND NONATTAINMENT ‘‘LINKAGES’’ FOR 8-HOUR OZONE
Upwind state
Alabama ................
Arkansas ...............
Georgia .................
Illinois ....................
Indiana ..................
Kentucky ...............
Louisiana ...............
Mississippi .............
Missouri .................
Tennessee ............
Texas ....................
Downwind receptor sites
East Baton Rouge, LA
(220330003).
East Baton Rouge, LA
(220330003).
East Baton Rouge, LA
(220330003).
Brazoria, TX (480391004)
Brazoria, TX (480391004)
Brazoria, TX (480391004)
Brazoria, TX (480391004)
East Baton Rouge, LA
(220330003).
Brazoria, TX (480391004)
East Baton Rouge, LA
(220330003).
East Baton Rouge, LA
(220330003).
Brazoria, TX (480391004) ...
Harris, TX (482010051) .......
Harris, TX (482010055).
Brazoria, TX (480391004) ...
Harris, TX (482010051) .......
Harris, TX (482010055).
Harris, TX (482010051) .......
Harris, TX (482010051) .......
Harris, TX (482010051) .......
Harris, TX (482010051) .......
Brazoria, TX (480391004) ...
Harris,
Harris,
Harris,
Harris,
Harris,
(482010055).
(482010055).
(482010055).
(482010055).
(482010051) .......
Harris, TX (482010055).
Harris, TX (482010051) .......
Brazoria, TX (480391004) ...
Harris, TX (482010055).
Harris, TX (482010051) .......
Harris, TX (482010055).
Brazoria, TX (480391004).
...
...
...
...
...
TX
TX
TX
TX
TX
TABLE V.D–9—UPWIND STATE TO DOWNWIND MAINTENANCE ‘‘LINKAGES’’ FOR 8-HOUR OZONE
Upwind state
Alabama ................
Arkansas ...............
Florida ...................
Georgia .................
Illinois ....................
Indiana ..................
Iowa ......................
Kansas ..................
Kentucky ...............
Louisiana ...............
Maryland ...............
Michigan ................
Mississippi .............
Missouri .................
New Jersey ...........
New York ..............
North Carolina .......
Ohio ......................
Oklahoma ..............
Pennsylvania .........
South Carolina ......
Tennessee ............
Texas ....................
Virginia ..................
West Virginia .........
Wisconsin ..............
Downwind receptor sites
Harris, TX (482010029) .......
Allegan, MI (260050003).
Harris, TX (482010029) .......
Harris, TX (482010029) .......
Fairfield, CT (90011123) ......
Fairfield, CT (90011123) ......
Allegan, MI (260050003).
Allegan, MI (260050003).
Fairfield, CT (90011123) ......
Harris, TX (482010029) .......
Fairfield, CT (90011123) ......
Harford, MD (240251001).
Harris, TX (482010029) .......
Allegan, MI (260050003).
Fairfield, CT (90011123) ......
Fairfield, CT (90011123) ......
New Haven, CT (90093002)
Fairfield, CT (90011123) ......
Allegan, MI (260050003).
Fairfield, CT (90011123) ......
Harris, TX (482010029).
Fairfield, CT (90011123) ......
Allegan, MI (260050003).
Fairfield, CT (90011123) ......
Fairfield, CT (90011123) ......
Allegan, MI (260050003).
VI. Quantification of State Emission
Reductions Required
A. Cost and Air Quality Structure for
Defining Reductions
ebenthall on DSK6TPTVN1PROD with RULES2
1. Summary
Section V, above, describes EPA’s
approach to identifying upwind states
with air quality contributions that meet
or exceed the air quality thresholds
discussed therein for each of the
NAAQS addressed in this rule. A state
is covered by the Transport Rule if its
contributions meet or exceed one of
those air quality thresholds and the
Agency identifies, using the cost- and
air quality-based approach described
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19:20 Aug 05, 2011
Jkt 223001
Harris, TX (482011050).
Harris, TX (482011050).
Harris, TX (482011050).
Allegan, MI (260050003) .....
New Haven, CT (90093002)
New Haven, CT (90093002)
Harris, TX (482011050).
New Haven, CT (90093002).
Harris, TX (482011050).
Harford, MD (240251001) ....
Allegan, MI (260050003).
Harford, MD (240251001) ....
Harris, TX (482011050).
Harris, TX (482011050).
New Haven,
New Haven,
Harford, MD
New Haven,
CT (90093002).
CT (90093002)
(240251001).
CT (90093002)
Harford, MD (240251001).
New Haven, CT (90093002)
Harford, MD (240251001).
Harford, MD (240251001) ....
Harris, TX (482011050).
New Haven, CT (90093002)
New Haven, CT (90093002)
Harford, MD (240251001).
Harford, MD (240251001).
Harford, MD (240251001).
below, emissions within the state that
constitute the state’s significant
contribution to nonattainment and
interference with maintenance with
respect to the 1997 ozone, 1997 PM2.5 or
2006 PM2.5 NAAQS.
In this section, EPA explains its final
cost- and air quality-based approach to
quantify the amount of emissions that
represent significant contribution to
nonattainment and interference with
maintenance for each state. EPA then
applies that approach for the three
different NAAQS being addressed in
this rule: The 1997 ozone NAAQS, the
1997 annual PM2.5 NAAQS and the 2006
24-hour PM2.5 NAAQS. EPA believes
that the methodology finalized could
PO 00000
Frm 00040
Fmt 4701
Sfmt 4700
also be used to address transport
concerns under other NAAQS,
including future revisions to the ozone
and PM2.5 NAAQS.
EPA applies the methodology
described herein to fully quantify the
emissions that constitute each covered
state’s significant contribution to
nonattainment and interference with
maintenance with respect to the 1997
annual PM2.5 and the 2006 24-hour
PM2.5 NAAQS. The FIPs with respect to
the annual and 24-hour PM2.5 NAAQS
that are finalized in this action ensure
that all such emissions are prohibited.
Each such FIP thus fully satisfies the
requirements of 110(a)(2)(D)(i)(I) with
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08AUR2
ebenthall on DSK6TPTVN1PROD with RULES2
Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
respect to the annual and/or 24-hour
PM2.5 NAAQS for the covered state.
EPA also applies the methodology to
quantify significant contribution to
nonattainment and interference with
maintenance with respect to the 1997
ozone NAAQS. However, we have not
been able to fully quantify such
emissions for all covered states. In this
action, EPA fully quantifies the
significant contribution to
nonattainment and interference with
maintenance for 15 states. We finalize
FIPs with respect to the 1997 ozone
standards for 10 of these 15 states
(Florida, Maryland, New Jersey, New
York, North Carolina, Ohio,
Pennsylvania, South Carolina, Virginia,
and West Virginia). We are also
publishing a supplemental notice of
rulemaking to take comment on whether
FIPs should be finalized for the
remaining 5 states (Iowa, Kansas,
Michigan, Oklahoma, and Wisconsin).
The FIPs for these 10 states (and the
FIPs for the remaining 5 states, if
finalized) fully satisfy the requirements
of 110(a)(2)(D)(i)(I) with respect to the
1997 ozone NAAQS for the covered
state.
In addition, we apply the
methodology described herein to
quantify, for 11 additional states, ozoneseason NOX emission reductions that
are necessary but may not be sufficient
to eliminate all significant contribution
to nonattainment and interference with
maintenance in other states. We finalize
FIPs with respect to the 1997 ozone
standards for 10 of these 11 states
(Alabama, Arkansas, Georgia, Illinois,
Indiana, Kentucky, Louisiana,
Mississippi, Tennessee, and Texas). We
are also publishing a supplemental
notice of rulemaking to take comment
on whether FIPs should be finalized for
the remaining state (Missouri). The FIPs
for these 10 states (and the FIP for the
remaining state, if finalized) make
measurable progress toward satisfying
the requirements of 110(a)(2)(D)(i)(I)
with respect to the 1997 ozone NAAQS
in each covered state. To the extent that
significant contribution to
nonattainment and interference with
maintenance is not entirely eliminated
for the 1997 ozone NAAQS through
today’s action, EPA will address these
instances in a future rulemaking. This is
further explained in section VI.D.
With respect to the 1997 annual PM2.5
NAAQS, this rule finds that 18 states
have SO2 and NOX emission reduction
responsibilities. EPA also finds that 21
states have SO2 and NOX emission
reduction responsibilities with respect
to the 2006 24-hour PM2.5 NAAQS.
There are a total of 23 states that have
SO2 and NOX emission reduction
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responsibilities for one or both of the
above PM2.5 NAAQS. We apply the
methodology to quantify emission
reductions that these states must
achieve to eliminate the state’s
significant contribution to
nonattainment and interference with
maintenance. The states are listed in
Table III–1 in section III of this
preamble.
This rule will prohibit all significant
contribution to nonattainment and
interference with maintenance with
respect to the annual and 24-hour PM2.5.
In addition, it will resolve air quality
issues at most nonattainment and
maintenance receptors identified by
EPA. EPA projects that unresolved
nonattainment and maintenance issues
will remain in only a few downwind
states after promulgation and
implementation of the Transport Rule.
For the annual PM2.5 standard, EPA
projects that this rule will help assure
that all areas in the east fully resolve
their nonattainment and maintenance
concerns. This rule will also help a
number of areas achieve the standard
earlier than they may have otherwise.
For the 2006 24-hour PM2.5 NAAQS, one
area is projected to remain in
nonattainment (Liberty-Clairton) and
three areas are projected to have
remaining maintenance concerns after
imposition of the Transport Rule
(Chicago,39 Detroit, and Lancaster
County).40
The methodology provides similar
assistance for ozone, assuring upwind
reductions that will assist downwind
states in controlling ozone pollution. It
reduces ozone concentration levels in
2012 and helps assure that all but two
downwind areas fully resolve their
nonattainment and maintenance
problems with the 1997 ozone NAAQS
by 2014. While Houston is projected to
still face nonattainment and Baton
Rouge is projected to still face
maintenance concerns with the 1997
ozone NAAQS, the Transport Rule
improves air quality in these two areas
and provides both health benefits and
assistance for these local areas in
meeting the NAAQS requirements. For
reasons explained below, EPA will
conduct further analysis in a subsequent
transport-related rulemaking to
determine whether further upwind state
39 This area is not currently designated as
nonattainment for the 24-hour PM2.5 standard. EPA
is portraying the receptors and counties in this area
as a single 24-hour maintenance area based on the
annual PM2.5 nonattainment designation of
Chicago-Gary-Lake County, IL-IN.
40 In the Transport Rule proposal, EPA noted that
the Liberty-Clairton receptor in Allegheny county
was significantly impacted by local emissions from
a sizeable coke production facility and other nearby
sources (75 FR 45281).
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48247
reductions are warranted to assist
attainment and maintenance of the
ozone NAAQS in Houston and Baton
Rouge areas.
When EPA proposed this air-quality
and cost-based multi-factor approach to
identify emissions that constitute
significant contribution to
nonattainment and interference with
maintenance from upwind states with
respect to the 1997 ozone, annual PM2.5,
and 2006 24-hour PM2.5 NAAQS, the
Agency indicated that the approach was
designed to be applicable to both
current and potential future ozone and
PM2.5 NAAQS (75 FR 45214). EPA
believes that the final Transport Rule
demonstrates the value of this approach
for addressing the role of interstate
transport of air pollution in
communities’ ability to comply with
current and future NAAQS. EPA
believes that the Transport Rule’s
approach of using air-quality thresholds
to determine upwind-to-downwindstate linkages and using the cost- and air
quality-based multi-factor approach to
quantify significant contribution to
nonattainment and interference with
maintenance (i.e., to determine the
specific amount of emissions that each
upwind state must reduce) could serve
as a precedent for quantifying upwind
state emission reduction responsibilities
with respect to potential future NAAQS.
One commenter suggested that the
rule could set a flawed precedent for
future transport analyses and remedies,
as it does not fully eliminate the
prohibited emissions in every upwind
state. EPA disagrees with this
characterization of the Transport Rule.
EPA notes that the partial determination
of significant contribution to
nonattainment and interference with
maintenance for certain upwind states
in the Transport Rule with respect to the
ozone NAAQS is not a function of the
multi-factor approach itself, but is
instead a function of its limited
application in this rulemaking to
identify emission reductions from a
single source category (EGUs). In fact,
the Transport Rule’s approach itself
allowed EPA to determine for which
upwind states we have identified all
emissions that constitute significant
contribution to nonattainment and
interference with maintenance, and for
which upwind states we have identified
emissions that are necessary but may
not be sufficient to eliminate the
prohibited emissions. As EPA explained
at proposal, developing the additional
information needed to consider NOX
emissions from non-EGU source
categories in order to fully quantify
upwind state responsibility with respect
to the 1997 ozone NAAQS would
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substantially delay promulgation of the
Transport Rule. EPA explained that we
do not believe that effort should delay
the emission reductions and large health
benefits this final rule will deliver
(75 FR 45213). EPA further explained
that we believe it is likely that the
Agency can provide the greatest
assistance to states in addressing
transported pollution by issuing a
separate (subsequent) rule to address
additional reductions that may be
necessary to fully eliminate upwind
state responsibility with respect to the
1997 ozone NAAQS (75 FR 45288).
Thus, EPA decided to promulgate the
Transport Rule as quickly as possible.
EPA anticipates that application of this
air-quality and cost-based multi-factor
approach to a broader set of source
categories in a subsequent rulemaking
will identify any remaining prohibited
emissions in the upwind states for
which the Transport Rule may not fully
eliminate those emissions with respect
to the 1997 ozone NAAQS.
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2. Background
After using air quality analysis to
identify upwind states that are ‘‘linked’’
to downwind air quality monitoring
sites with nonattainment and
maintenance problems through
contribution of at least one percent of
the relevant NAAQS, EPA quantifies the
portion of each state’s contribution that
constitutes its ‘‘significant contribution’’
or ‘‘interference with maintenance.’’
This section describes the
methodology developed by EPA for this
analysis and then explains how that
methodology is applied to measure
significant contribution to
nonattainment and interference with
maintenance with respect to the
NAAQS of concern. For this portion of
the analysis, EPA expands upon the
methodology used in the NOX SIP Call
and CAIR but modifies it in important
respects. In the NOX SIP Call and CAIR,
EPA’s methodology defined significant
contribution as those emissions that
could be removed with the use of
‘‘highly cost effective’’ controls. In the
Transport Rule, rather than relying
solely on an analysis of what constitutes
‘‘highly cost effective’’ controls, EPA
relies on an analysis that accounts for
both cost and air quality improvement
to identify the portion of a state’s
contribution that constitutes its
significant contribution to
nonattainment and interference with
maintenance. Furthermore, in response
to the Court’s opinion in North
Carolina, EPA has developed an
approach which gives independent
meaning to the ‘‘interfere with
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maintenance’’ prong of section
110(a)(2)(D)(i)(I).
The methodology takes into account
both the D.C. Circuit Court’s
determination that EPA may consider
cost when measuring significant
contribution, Michigan, 213 F.3d at 679,
and its rejection of the manner in which
cost was used in the CAIR analysis,
North Carolina, 531 F.3d at 917. It also
recognizes that the Court accepted—but
did not require—EPA’s use of a single,
uniform cost threshold to measure
significant contribution. Michigan, 213
F.3d at 679.
As EPA discussed at length in the
Transport Rule proposal, using both air
quality and cost factors allows EPA to
consider the full range of circumstances
and state-specific factors that affect the
relationship between upwind emissions
and downwind nonattainment and
maintenance problems (75 FR 45271).
For example, considering cost takes into
account the extent to which existing
plants are already controlled as well as
the potential for, and relative difficulty
of, additional emission reductions.
Therefore, EPA believes that it is
appropriate to consider both cost and air
quality metrics when quantifying each
state’s significant contribution.
This methodology is consistent with
the statutory mandate in section
110(a)(2)(D)(i)(I) which requires upwind
states to prohibit emissions that
significantly contribute to
nonattainment or interference with
maintenance in another state. As
discussed in more detail in the
proposal, interpreting significant
contribution to nonattainment and
interference with maintenance
inherently involves a decision on how
much emissions control responsibility
should be assigned to upwind states,
and how much responsibility should be
left to downwind states. EPA’s
methodology is intended to ‘‘assign a
substantial but reasonable amount of
responsibility to upwind states. * * *to
control their emissions’’ (75 FR 45272).
EPA believes that upwind states
contributing to downwind state air
quality degradation should bear
substantial responsibility to control
their emissions because of the plain
language of the good neighbor
provision, the health risks and control
cost impacts that upwind emissions
cause in the downwind state, and the
cumulative impact in the downwind
state of emissions from multiple upwind
states, and the importance of achieving
attainment in downwind states as
expeditiously as practicable but no later
than specific deadlines as required by
the Act. EPA’s approach does not shift
the responsibility for achieving or
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maintaining the NAAQS to the upwind
state. See 75 FR 45272.
The methodology defines each state’s
significant contribution to
nonattainment and interference with
maintenance as the emission reductions
available at a particular cost threshold
in a specific upwind state which
effectively address nonattainment and
maintenance of the relevant NAAQS in
the linked downwind states of concern.
Unlike the NOX SIP Call and CAIR,
where EPA’s significant contribution
analysis had a regional focus, the
methodology used in the Transport Rule
focuses on state-specific factors. The
methodology uses a multi-step process
to analyze costs and air quality impacts,
identify appropriate cost thresholds,
quantify reductions available from EGUs
in each state at those thresholds, and
consider the impact of variability in
EGU operations. There are four steps to
this methodology: (1) Identification of
each state’s emission reductions
available at ascending costs per ton as
appropriate; (2) assessment of those
upwind emission reductions’
downwind air quality impacts; (3)
identification of upwind ‘‘cost
thresholds’’ delivering effective
emission reductions and downwind air
quality improvement; and (4)
enshrinement of the upwind emission
reductions available at those cost
thresholds in state budgets.
In step one, EPA identifies what
emission reductions are available at
various cost thresholds, quantifying
emission reductions that would occur
within each state at ascending costs per
ton of emission reductions. In other
words, EPA determined for specific cost
per ton thresholds, the emission
reductions that would be achieved in a
state if all EGUs greater than 25 MW in
that state used all emission controls and
emission reduction measures available
at that cost threshold. For purposes of
this discussion, we refer to these as
‘‘cost curves.’’
For this final rule, EPA used updated
IPM modeling to conduct a similar cost
curve analysis as conducted in the
Transport Rule proposal (75 FR 45275).
In the proposal, the cost curves only
reflected escalating cost for one
pollutant while the other pollutant cost
was held constant at base case levels
(i.e., $0/ton). However, EPA improved
the costing analysis for the final rule by
identifying upwind emission reductions
available as costs were imposed on both
SO2 and NOX simultaneously for states
linked to downwind states on the basis
of the PM2.5 NAAQS. In other words, the
cost curves in the proposal depicted
state level emissions when only one
pollutant was priced (i.e., NOX at $500/
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ton). Separate cost curves were done for
each pollutant. For the final rule, EPA
conducted some preliminary cost curve
analysis for identifying NOX thresholds
in this manner. However, for the final
cost curve analysis, EPA relied on cost
curves that reflected state emissions
when pollutants were priced
simultaneously (e.g., NOX at $500/ton
and SO2 at $1,600/ton). For reasons
described in section VI.B, EPA was able
to conduct this type of analysis because
the preliminary cost curves specific to
annual and ozone-season NOX suggested
little flexibility in adjusting the $500/
ton cost thresholds imposed for each.
Therefore, EPA was able to hold the cost
threshold constant at $500/ton for these
pollutants in its examination of SO2 at
various cost thresholds. EPA believes
this approach to cost analysis is a better
simulation of the Transport Rule’s likely
impact on covered sources. Under the
final Transport Rule, covered sources in
states regulated for PM2.5 must address
compliance requirements for SO2 and
NOX emissions simultaneously, and this
refined approach to cost curve analysis
and subsequent air quality analysis
better reflects this reality. Section VI.B
of this preamble describes the costing
analysis in further detail. Also, for more
detail on the development of the cost
curves, see ‘‘Significant Contribution
and State Emission Budgets Final Rule
TSD’’ in the docket for this rule.
Although the cost curves presented in
this rule only include EGU reductions,
EPA also assessed the cost of SO2 and
NOX emission reductions available for
source categories other than EGUs in the
proposed rulemaking. This preliminary
assessment in the rule proposal
suggested that there likely would be
very large emission reductions available
from EGUs before costs reach the point
for which non-EGU sources have
available reductions (75 FR 45272). EPA
revisited these non-EGU reduction cost
levels in this final rulemaking and
verified that there are little or no
reductions available from non-EGUs at
costs lower than the thresholds that EPA
has chosen ($500/ton for NOX, $2,300/
ton for SO2).
Further details on EPA’s application
of cost curves are provided below, in
section VI.B.
In step two, EPA uses an air quality
assessment tool to estimate the impact
that the combined reductions available
from upwind contributing states and the
downwind receptor state at different
cost-per-ton levels would have on air
quality at downwind monitoring sites
projected to have nonattainment and/or
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maintenance problems.41 While less
rigorous than the air quality models
used for attainment demonstrations,
EPA believes this air quality assessment
tool (which has been refined since
proposal) is acceptable for assessing the
impact of numerous options for upwind
emission reductions in the process of
defining an upwind state’s significant
contribution to nonattainment and
interference with maintenance. It allows
the Agency to anticipate specific air
quality impacts of many more potential
emission reduction scenarios pertinent
to the relevant NAAQS than time- and
resource-intensive comprehensive air
quality modeling would permit.
Further details on EPA’s application
of step two in this methodology are
provided below, in section VI.C.
In step three, EPA examines cost and
air quality information to identify
‘‘significant cost thresholds.’’ EPA
considered a significant cost threshold
to be a point along the cost curves
where a noticeable change occurred in
downwind air quality, such as a point
where large upwind emission
reductions become available because a
certain type of emissions control
strategy becomes cost-effective.42
This methodology allows EPA, where
appropriate, to define multiple cost
thresholds that vary for a particular
pollutant for different upwind states. As
explained in the Transport Rule
proposal, EPA does not believe it is
required to utilize multiple cost
thresholds to regulate upwind emissions
for purposes of the mandate in CAA
section 110(a)(2)(D), but EPA’s multifactor methodology developed for the
Transport Rule to define significant
contribution to nonattainment and
interference with maintenance allows
the Agency to consider whether a single
cost threshold or multiple cost
thresholds are appropriate for meeting
the requirements of CAA section
110(a)(2)(D) relevant to a particular
NAAQS (75 FR 45274).
41 As is discussed in the RIA, EPA also used the
CAMx model to perform air quality analysis of its
proposed remedy to address significant
contribution. Results from this modeling will not
exactly correspond to results from the air quality
assessment tool both because the inputs to the air
quality modeling are different and the sophisticated
model more fully accounts for the complex air
chemistry interactions. The full air quality
modeling looks at the remedy, including reductions
in upwind states that do not contribute as well as
the impacts of the variability provisions discussed
later in this section. It also provides a metric against
which to evaluate the air quality assessment tool.
42 The cost thresholds identified in this rule are
specific to the section 110(a)(2)(D)(i)(I)
requirements for the states and NAAQS considered
in this proposal. They do not represent an agency
position on the appropriateness of such cost
thresholds for any other application under the Act.
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48249
In step four, EPA uses the information
regarding emission reductions available
in each ‘‘linked’’ upwind state at the
appropriate cost threshold to form a
state ‘‘budget,’’ representing the
remaining emissions from covered
sources for the state in an average year
once significant contribution to
nonattainment and interference with
maintenance have been eliminated; each
budget also allows for the identification
of an associated variability limit. These
budgets and variability limits are used
to develop enforceable requirements
under the final remedy. The final rule’s
methodology for identifying state
budgets is derived directly from the cost
curves and multi-factor analysis EPA
uses to determine each state’s
significant contribution to
nonattainment and interference with
maintenance. State emission budgets are
discussed in section VI.D and the
variability limits are discussed in
section VI.E.
B. Cost of Available Emission
Reductions (Step 1)
This subsection provides more detail
on the cost curves that EPA developed
to assess the costs of reducing SO2 and
NOX emissions to address transport
related to ozone and PM2.5
concentrations (described previously as
Step 1). It summarizes the information
from the curves and then provides
EPA’s interpretation of that information.
EPA used IPM to develop the EGU cost
curves described in this rulemaking.
More information can be found
regarding EPA’s use of IPM for the final
Transport Rule in the ‘‘Significant
Contribution and State Emission
Budgets Final Rule TSD’’.
The amount of emission reductions
that the cost curves suggest are available
at various costs are specific to the 2012
and 2014 time periods. These cost
estimates factor in the time interval
between rule finalization and
compliance periods, existing controls
already in place, and controls that could
potentially come on line by the start of
the compliance period. EPA notes that
cost curves are a fluid concept and
would vary given different compliance
dates.
1. Development of Annual NOX and
Ozone-Season NOX Cost Curves
EPA conducted preliminary cost
curve analysis for annual NOX and
ozone-season NOX in a similar manner
to that used in the proposed rulemaking.
That is, the impact of various cost
thresholds on emissions was examined
individually. For example, state level
emissions were examined at cost levels
for annual NOX of $500, $1,000, and
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$2,500/ton while SO2 was held at base
case levels. EPA used this approach to
examine NOX and ozone-season NOX
emission reductions available from
EGUs by 2012 and 2014 at various cost
levels, reaching to $2,500/ton for annual
NOX and up to $5,000/ton for ozoneseason NOX (in 2007-year dollars).
Section VI.D explains why EPA
analyzed the $500/ton threshold for
annual and ozone-season NOX. EPA
selected two higher cost thresholds to
analyze for annual and ozone-season
NOX that provided a reasonable
spectrum of emission reduction
opportunities from EGUs at higher cost
thresholds. Specifically, EPA analyzed
these two higher cost thresholds
because the first ($1,000/ton) was
informative in regards to the additional
EGU NOX emissions reductions
available without installation of
advanced controls, and the second
($2,500/ton for annual NOX, $5,000/ton
for ozone-season NOX) was informative
in regards to additional EGU reductions
available at cost thresholds where
advanced NOX control retrofits are
economic for some units. The cost
thresholds were only applied to states
with air quality contributions that meet
or exceed the air quality thresholds as
identified in section V.D. For both
annual and ozone-season NOX, EPA did
not consider cost thresholds below
$500/ton for reasons explained in
section VI.D.
EPA observed in the proposal that
low-cost NOX reductions are available at
upwind sources with existing pollution
control equipment that may not
otherwise be operated in the future
without the Transport Rule. EPA
believes it is appropriate to prohibit any
‘‘linked’’ upwind state from potentially
increasing its emissions through a
failure to operate these existing
pollution controls, which could worsen
downwind air quality problems. Thus,
EPA reflected operation of these
controls in all modeling of different cost
thresholds (i.e., the modeling assumes
year-round operation of postcombustion NOX controls in covered
PM2.5 states and ozone-season operation
of post-combustion NOX controls in
covered ozone states).
Table VI.B–1 shows the annual NOX
emissions from EGUs at various levels
of control cost per ton for 2014. Table
VI.B–2 presents the cost curves for
ozone-season NOX emissions from
EGUs. As discussed in section VI.D,
EPA determined that $500/ton for
annual and ozone NOX was the
appropriate cost threshold for this rule
(although EPA plans to determine in the
future whether a higher cost/ton
threshold may be warranted for states
contributing to nonattainment or
maintenance problems with the 1997
ozone air quality standard projected to
remain in two downwind areas).
TABLE VI.B–1—2014 ANNUAL NOX EMISSIONS FROM FOSSIL-FUEL FIRED EGUS GREATER THAN 25 MW FOR EACH
TRANSPORT RULE STATE AT VARIOUS COSTS PER TON
[(2007$) per ton (thousand tons)]
Base case level
$500
$1,000
$2,500
Alabama ...........................................................................................
Georgia ............................................................................................
Illinois ...............................................................................................
Indiana .............................................................................................
Iowa .................................................................................................
Kansas .............................................................................................
Kentucky ..........................................................................................
Maryland ..........................................................................................
Michigan ...........................................................................................
Minnesota ........................................................................................
Missouri ............................................................................................
Nebraska ..........................................................................................
New Jersey ......................................................................................
New York .........................................................................................
North Carolina ..................................................................................
Ohio .................................................................................................
Pennsylvania ....................................................................................
South Carolina .................................................................................
Tennessee .......................................................................................
Texas ...............................................................................................
Virginia .............................................................................................
West Virginia ....................................................................................
Wisconsin .........................................................................................
75
48
55
117
45
32
83
17
64
38
55
43
8
19
46
99
132
38
29
141
36
64
37
72
41
51
108
40
25
83
17
61
30
54
27
8
19
46
95
124
38
29
138
35
64
32
72
41
50
107
39
25
81
17
61
30
54
26
8
18
46
94
124
37
29
138
35
64
32
70
39
49
100
37
23
78
17
60
30
51
21
8
18
44
92
116
36
29
136
28
61
31
Total ..........................................................................................
1,321
1,236
1,229
1,174
TABLE VI.B–2—2012 OZONE-SEASON NOX EMISSIONS FROM FOSSIL-FUEL FIRED EGUS GREATER THAN 25 MW FOR
EACH TRANSPORT RULE STATE AT VARIOUS COSTS
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[(2007$) per ton (thousand tons)]
Base case level
Alabama ...........................................................................................
Arkansas ..........................................................................................
Florida ..............................................................................................
Georgia ............................................................................................
Illinois ...............................................................................................
Indiana .............................................................................................
Kentucky ..........................................................................................
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15
42
29
21
47
38
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$500
$1,000
34
15
27
28
21
46
37
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34
15
27
28
21
46
36
08AUR2
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14
24
25
21
43
34
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48251
TABLE VI.B–2—2012 OZONE-SEASON NOX EMISSIONS FROM FOSSIL-FUEL FIRED EGUS GREATER THAN 25 MW FOR
EACH TRANSPORT RULE STATE AT VARIOUS COSTS—Continued
[(2007$) per ton (thousand tons)]
Base case level
$500
$1,000
$5,000
Louisiana ..........................................................................................
Maryland ..........................................................................................
Mississippi ........................................................................................
New Jersey ......................................................................................
New York .........................................................................................
North Carolina ..................................................................................
Ohio .................................................................................................
Pennsylvania ....................................................................................
South Carolina .................................................................................
Tennessee .......................................................................................
Texas ...............................................................................................
Virginia .............................................................................................
West Virginia ....................................................................................
13
7
10
3
8
23
42
53
15
16
65
15
26
13
7
10
3
8
23
42
53
15
16
63
15
26
13
7
10
3
8
23
42
52
15
15
63
15
26
13
7
9
3
8
21
38
49
14
15
60
13
24
Total ..........................................................................................
523
504
501
467
EPA notes that the cost curves
presented here differ somewhat from the
cost curves presented in the proposal.
The NOX emissions modeled at a $500/
ton cost threshold for the final rule are
lower than they were at proposal. In
addition, the emission reductions they
represent from the updated base case are
not as pronounced as was found in
modeling for the proposed rule. It is
worth emphasizing that the lower
emission reductions observed at $500/
ton in this final rulemaking are due to
a lower starting point in updated base
case EGU NOX emission levels (and thus
do not reflect higher NOX emissions
remaining after the reductions made at
the $500/ton threshold). While the base
case 2012 nationwide annual EGU NOX
emissions were approximately 3 million
tons in the proposal, they were only 2.1
million tons in the final rule. This
approximately 33 percent reduction in
base case EGU NOX emissions in the
final rule modeling relative to the
proposal is due to a combination of
modeling updates, including lower
natural gas prices, reduced electricity
demand, newly-modeled consent
decrees and state rules, and updated
NOX rates to reflect 2009 emissions
data. All of these factors resulted in
substantially lower base case Transport
Rule NOX emissions in the final rule
modeling.
ebenthall on DSK6TPTVN1PROD with RULES2
2. Development of SO2 Cost Curves
As explained in detail below in
section VI.D, EPA determined that a
single threshold of $500/ton for ozoneseason NOX control in the states covered
for the 1997 ozone NAAQS and a single
threshold of $500/ton for annual NOX
control in the states covered for the
PM2.5 NAAQS were appropriate cost
thresholds for identifying upwind
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control under the Transport Rule. With
these parameters determined, EPA was
able to assess the availability of SO2
emission reductions from EGUs at
various SO2 cost per ton thresholds with
the corresponding NOX reduction
requirements simultaneously
represented in the analysis.
This approach of simultaneously
modeling cost levels for covered
pollutants is different from the approach
taken in the proposal. In the proposal,
cost curves were developed and
examined independently for each
pollutant. For example, with the SO2
cost curves in the proposal, the NOX
cost level was held constant at base case
levels as the SO2 cost threshold was
varied from base case levels to $2,400/
ton. Commenters noted that this did not
accurately reflect a reality where source
owners/operators view price signals for
all covered pollutants simultaneously
and make operation decisions
accordingly. For the final rule, EPA
included cost thresholds of $500/ton for
annual NOX in PM2.5 states and $500/
ton for ozone-season NOX in ozoneseason states while examining different
SO2 cost thresholds. This allows EPA to
develop final cost curves for air quality
analysis and budget determination that
reflect EGU operation when faced with
the appropriate cost thresholds on all
covered pollutants. EPA believes this
approach of modeling final cost curves
is superior to the methodology used in
the proposal because it reflects market
signals for each pollutant
simultaneously, as would be
experienced by states and sources
regulated under the Transport Rule.
In this manner, EPA examined several
SO2 cost thresholds of $500, $1,600,
$2,300, $2,800, $3,300 and $10,000 per
ton. EPA selected these cost thresholds
PO 00000
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Fmt 4701
Sfmt 4700
for the final rule’s analysis as a
representative sampling of points along
the SO2 cost curve thoroughly explored
at proposal. Modeling of these cost
thresholds provided a spectrum of
emission reduction opportunities
yielding meaningful differences to
consider in total costs and air quality
improvements at each threshold. The
proposal’s more detailed analysis using
smaller increments between cost
thresholds outlined the general form of
the sector’s SO2 emission reduction cost
curve and therefore allowed EPA to use
larger increments between cost
thresholds for the final rule’s analysis.
Each of the cost thresholds examined for
the final rule represents a point where
there is a significant change in available
controls, emission reductions, or costs
and economic impacts. EPA believes
analysis of these thresholds illustrate a
meaningful progression of costs and air
quality impacts that enabled the Agency
to determine a proper threshold along
this cost curve to identify significant
contribution to nonattainment and
interference with maintenance for this
rulemaking.
The cost thresholds above $500/ton
were applied starting in 2014. In all
modeling, the 2012 cost per ton
threshold was held constant at $500/ton
as EPA believes that this cost threshold
captures all emission reductions feasible
by 2012 (see section VI.B.3 below for
more discussion). At the higher cost
levels (e.g., $2,800/ton and above), the
curve does not include all available
reductions as they do not include nonEGU reductions. As described above for
NOX, EPA also observed at proposal that
substantial low-cost SO2 reductions are
available from the operation of existing
scrubbers that may not otherwise
operate in the future without the
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
Transport Rule in place. Therefore, all
of the final SO2 cost curves assume
operation of existing scrubbers in PM2.5
states under the Transport Rule. In
2014, approximately 3 million tons of
SO2 reductions can be achieved at the
$500/ton cost threshold through
operation of existing controls and some
fuel switching.
This final cost curve also
appropriately reflects the Group 1/
Group 2 distinction for states covered
for PM2.5. As discussed in more detail in
section VI.D, EPA identified Group 2
states as those that were linked to states
where all nonattainment and
maintenance issues had been resolved at
$500/ton levels. There is no longer any
significant contribution to
nonattainment or interference with
maintenance by these seven Group 2
states at levels above $500/ton.
Therefore, in the final curves, these
Group 2 states’ cost thresholds were
held constant at $500/ton as the higher
cost thresholds were applied to the
remaining Group 1 states starting in
2014. For example, the modeled
emissions at the $2,300 per ton cost
threshold shown in Table VI.B–3 below
reflect each state’s emissions when
Group 1 states are subjected to a $2,300
per ton SO2 constraint and Group 2
states are subjected to a $500/ton SO2
constraint.
Additional reductions can be
achieved at the higher cost thresholds.
The cost curves demonstrate that
sources begin to build significant
additional flue gas desulfurization
(FGD) retrofits at an SO2 cost threshold
of $1,600 per ton and additional dry
sorbent injection (DSI) retrofits at an
SO2 cost threshold of $2,300 per ton.
With these final cost curves in hand,
EPA was able to identify the combined
reductions available from upwind
contributing states and the downwind
state, at different cost-per-ton levels.
Additionally, EPA was able to examine
the economic impacts of imposing such
cost constraints on power sector
generation. However, this only
constitutes a portion of EPA’s multifactor assessment used to determine the
amount of emissions that represent
significant contribution to
nonattainment and interference with
maintenance. As noted in the Transport
Rule proposal, EPA’s multi-factor
assessment considered air quality and
cost considerations when identifying
cost thresholds (75 FR 45271). The air
quality portion of the assessment is
described in section VI.C of the final
Transport Rule preamble.
3. Amount of Reductions That Could Be
Achieved by 2012 and 2014
EPA applied escalating SO2 cost per
ton thresholds for Group 1 states to
create the cost curves for 2014 and
beyond. For 2012 SO2, the cost per ton
was held constant at $500/ton as the
cost thresholds in 2014 and beyond
were varied. The advanced pollution
controls incentivized by these higher
cost-per-ton levels can reasonably be
installed by 2014. EPA also considered
whether any of these emission
reductions could be achieved prior to
2014. For the reasons that follow, EPA
concluded that significant reductions
could be achieved by 2012 and that it
is important to require all such
reductions by 2012 to ensure that they
are achieved as expeditiously as
practicable. SO2 and NOX reductions
come from operating existing controls,
installing combustion controls, fuel
switching, and increased dispatch of
lower-emitting generation which can be
achieved by 2012. In general,
compliance mechanisms that do not
involve post-combustion control
installation are feasible before 2014. For
this reason, EPA believes it is
appropriate to require these emissions
to be removed in 2012, consistent with
the Act’s requirement that downwind
states attain the NAAQS as
expeditiously as practicable.
Therefore, all of the cost curves
presented below include all feasible
2012 reductions up to a threshold of
$500/ton for SO2 and $500/ton for
annual NOX in states linked to receptors
for PM2.5, as well as $500/ton for ozoneseason NOX in states linked to receptors
for ozone. These cost per ton levels do
not precipitate advanced postcombustion control installation in 2012
(as EPA acknowledges that such
installations are not feasible by 2012),
but they do promote the compliance
options outlined above. The higher cost
thresholds for SO2 Group 1 states were
only applied starting in 2014. Therefore,
the 2012 state level emissions in the
‘‘$2,300 per ton threshold’’ reflect a cost
threshold of only $500/ton for all
pollutants (the $2,300 per ton value
starts in 2014 for Group 1 states’ SO2).
The table below illustrates the change
in state level SO2 emissions as the
higher cost per ton thresholds are
applied to Group 1 states.
TABLE VI.B–3—2014 SO2 EMISSIONS FROM FOSSIL-FUEL-FIRED EGUS GREATER THAN 25 MW FOR EACH TRANSPORT
RULE STATE AT VARIOUS COSTS PER TON
[Thousand tons] a
ebenthall on DSK6TPTVN1PROD with RULES2
State
SO2
group
Alabama ...........................................................................
Georgia ............................................................................
Illinois ...............................................................................
Indiana .............................................................................
Iowa ..................................................................................
Kansas .............................................................................
Kentucky ..........................................................................
Maryland ..........................................................................
Michigan ...........................................................................
Minnesota .........................................................................
Missouri ............................................................................
Nebraska ..........................................................................
New Jersey ......................................................................
New York .........................................................................
North Carolina ..................................................................
Ohio ..................................................................................
Pennsylvania ....................................................................
South Carolina .................................................................
Tennessee .......................................................................
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PO 00000
Frm 00046
Base
case
level
2
2
1
1
1
2
1
1
1
2
1
2
1
1
1
1
1
2
1
Fmt 4701
417
170
138
711
127
70
488
43
266
66
382
72
39
40
120
832
507
210
284
Sfmt 4700
$500
201
94
134
245
112
55
161
32
206
43
212
68
7
21
104
294
294
93
82
$1,600
226
94
130
179
78
57
126
28
189
45
173
70
7
20
61
175
164
100
63
E:\FR\FM\08AUR2.SGM
$2,300
213
95
124
161
75
61
106
28
144
46
166
70
7
12
58
137
112
103
59
08AUR2
$2,800
214
95
117
153
67
61
103
26
105
46
109
70
7
11
49
123
107
104
59
$3,300
236
95
102
121
45
61
89
24
94
46
84
70
6
10
40
115
102
104
59
$10,000
190
98
36
69
13
45
46
18
24
44
21
66
5
8
30
65
75
105
24
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
TABLE VI.B–3—2014 SO2 EMISSIONS FROM FOSSIL-FUEL-FIRED EGUS GREATER THAN 25 MW FOR EACH TRANSPORT
RULE STATE AT VARIOUS COSTS PER TON—Continued
[Thousand tons] a
Base
case
level
State
SO2
group
$500
$1,600
$2,300
$2,800
$3,300
$10,000
Texas ...............................................................................
Virginia .............................................................................
West Virginia ....................................................................
Wisconsin .........................................................................
2
1
1
1
453
65
497
125
281
59
157
51
282
51
122
47
284
35
76
40
281
33
74
38
281
32
72
34
243
16
55
14
Total ..........................................................................
..............
6,122
3,007
2,487
2,212
2,053
1,919
1,311
Group 1 total .............................................................
..............
4,665
2,172
1,612
1,340
1,180
1,025
520
Group 2 total .............................................................
..............
1,457
835
875
872
872
894
791
a Note:
As described in the preamble language for this section, the escalating cost per ton figures in each column header only apply to Group
1 states in 2014 and each year thereafter. Cost per ton for Group 2 states is held constant at $500/ton for all the costing runs. In some cases,
the escalating cost levels in Group 1 states affect emission levels in Group 2 states as some generation shifts between states in response to
newly imposed costs.
ebenthall on DSK6TPTVN1PROD with RULES2
C. Estimates of Air Quality Impacts
(Step 2)
After developing cost curves to show
the state-by-state cost-effective emission
reductions available, EPA estimates the
air quality impacts of these reductions
using the air quality assessment tool
coupled with full-scale air quality
modeling where possible. EPA uses the
air quality assessment tool to evaluate
the impact on air quality for downwind
nonattainment and maintenance
receptors from upwind reductions in
‘‘linked’’ states. This section describes
the development of the air quality
assessment tool and summarizes the
results of this evaluation.
1. Development of the Air Quality
Assessment Tool and Air Quality
Modeling Strategy
In response to comments on the
methodology used for the proposed rule,
EPA made significant improvements to
the air quality assessment tool (AQAT)
for the final Transport Rule.
Furthermore, EPA relied on CAMx to
model the air quality response to NOX
reductions and limited AQAT’s role
(relative to the Transport Rule proposal)
to estimating the relative response of
sulfate concentrations from SO2
reductions. EPA did not use AQAT to
address NOX reductions in the final rule
analyses. These and other changes to
our approach, as described below and in
the ‘‘Significant Contribution and State
Emission Budgets Final Rule TSD’’,
address commenter’s concerns about the
scientific rigor of the design and
application of AQAT and commenter’s
recommendations to rely upon air
quality modeling as part of this analysis.
For the final Transport Rule, EPA
created an AQAT calibration scenario
consisting of full-scale air quality
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modeling using CAMx of a 2014 control
scenario reflecting SO2 and NOX
emission reductions of similar
stringency and from the same geography
as the Transport Rule proposal.
Modeling of this AQAT calibration
scenario reflected all updates made to
the air quality modeling platform, as
described in the ‘‘Air Quality Modeling
Final Rule TSD’’ found in the docket for
this rulemaking. CAMx modeling of
each receptor’s response in this control
scenario accounts for complex chemical
interactions and covariation of these
pollutants. Among the important
atmospheric chemical interactions
accounted for in CAMx is ‘‘nitrate
replacement.’’ 43 Nitrate replacement
occurs when SO2 emission reductions
lead to decreases in ammonium sulfate,
which in turn, can result in an increase
in ammonium nitrate concentrations. As
described below, EPA used the CAMx
modeling results for this AQAT
calibration scenario together with the
modeling for the 2012 base case to
characterize the response of ozone,
nitrate, and sulfate at each
nonattainment and maintenance
receptor to the mix of upwind NOX and
SO2 emission reductions at each cost
threshold.
As described in section VI.D, EPA
determined that the $500/ton threshold
for upwind annual and ozone-season
NOX control is appropriate for the final
Transport Rule (although EPA plans to
determine in the future whether a
higher cost/ton threshold may be
43 Observable indicators of the sensitivity of PM
2.5
nitrate to emission reductions—Part II: Sensitivity
to errors in total ammonia and total nitrate of the
CMAQ-predicted non-linear effect of SO2 emission
reductions. R.L. Dennis, P.K. Bhave, and R.W.
Pinder. 2008. Atmospheric Environment (42):1287–
1300.doi:10.1016/j.atmosenv.2007.10.036.
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warranted for states contributing to
nonattainment or maintenance problems
with the 1997 ozone air quality standard
projected to remain at receptors in two
downwind areas 44). Because this
threshold corresponds to the NOX
control strategy modeled in the AQAT
calibration scenario described above,
EPA is able to rely on this CAMx air
quality modeling to assess the response
of ozone and nitrate concentrations due
to NOX reductions and does not
estimate ozone or nitrate impacts for
this final rulemaking using AQAT.
Further information on the air quality
modeling of this AQAT calibration
scenario can be found in the Air Quality
Modeling Final Rule TSD and the
Significant Contribution and State
Emission Budgets Final Rule TSD in the
docket for this rulemaking.
In order to estimate 2014 annual and
24-hour PM2.5 concentrations, AQAT
uses the 2012 annual and seasonal
contributions which quantify the
contribution of SO2 emissions in
specific upwind states to sulfate
concentrations at specific downwind
receptors. These contributions are
described in section V.D.2 and the Air
Quality Modeling Final Rule TSD.
EPA utilizes CAMx modeling of the
AQAT calibration scenario, described
above, to ‘‘calibrate’’ the contribution
factors by developing and applying
linear sulfate response factors for each
downwind receptor. These factors
calibrate each receptor’s sulfate
response to varying levels of upwind
SO2 emissions. These calibration factors
are based on the sulfate response
modeled by CAMx due to emission
changes occurring between the 2012
base case and the 2014 AQAT
44 Houston
E:\FR\FM\08AUR2.SGM
and Baton Rouge nonattainment areas.
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ebenthall on DSK6TPTVN1PROD with RULES2
calibration scenario. Calibration factors
were constructed for the annual and
24-hour PM2.5 AQAT.
To further allow adequate assessment
of the seasonal impacts of various levels
of upwind SO2 reductions on each
receptor’s 24-hour PM2.5 concentration
using AQAT, EPA developed response
factors for sulfate on a quarterly basis to
capture important air quality differences
between summer and winter emissions
and concentrations. This process
allowed EPA to estimate the air quality
values for each season at each cost
threshold, and then estimate the air
quality design values.
Finally, EPA’s air quality assessment
accounts for the impact that this
differential response in sulfate by
quarter can have on the ordering of 24hour concentrations when calculating
the 98th percentile for the 24-hour
standard. AQAT estimates quarterlyspecific relative response factors that
estimate quarterly-specific proportional
change in ammonium sulfate resulting
from the SO2 emission reduction from
the 2012 base case scenario to the 2014
cost threshold scenario being assessed.
These quarterly relative response factors
are then applied to each of the
maximum 24-hour PM2.5 concentrations
for eight days per quarter per year at
each receptor from the 2012 base case.
This methodology improvement allows
EPA to redetermine the 98th percentile
day for each year and recalculate
average and maximum design values for
the 24-hour PM2.5 standard.
These improvements for the final rule
increase EPA’s confidence that the air
quality estimates provided by AQAT,
now customized for this application,
more accurately estimate the results of
full-scale air quality modeling of the
various levels of upwind SO2 reductions
considered. EPA evaluated the estimates
from AQAT using an independent data
set, the 2014 base case estimates from
CAMx, finding that the results are
unbiased with minimal differences. See
‘‘Significant Contribution and State
Emission Budgets Final Rule TSD’’ for
more details.
As such, EPA believes the revised
AQAT provides an appropriate basis for
assessing the air quality portion of the
multi-factor methodology to define
significant contribution to
nonattainment and interference with
maintenance.45
45 EPA used CAMx to conduct full air quality
modeling of the final Transport Rule remedy
embodying the emission reductions that EPA first
selected on the basis of the multi-factor analysis
using AQAT to project air quality impacts from
varying levels of emission reductions analyzed. The
CAMx results confirmed the relative magnitude and
direction of AQAT’s estimates of the outcomes for
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2. Utilization of AQAT To Evaluate
Control Scenarios
For the final Transport Rule, EPA
performed air quality analysis for each
downwind annual and 24-hour PM2.5
receptor with a nonattainment and/or
maintenance problem in the 2012 base
case. For each receptor, EPA quantified
the sulfate reduction and resulting air
quality improvement when a group of
states consisting of the upwind states
that are ‘‘linked’’ to the downwind
receptor (as explained in section V.D)
and the downwind state where the
receptor is located, all made the SO2
emission reductions that EPA identified
as available at each cost threshold. EPA
assumes reductions at each cost
threshold from the linked upwind states
as well as the downwind receptor state
to assess the shared responsibility of
these upwind states to address air
quality at the identified receptors.
Analysis of each receptor did not
assume any emission reductions beyond
those included in the 2014 base case
from upwind states that are not
‘‘linked’’ to that specific downwind
receptor (even if the state was ‘‘linked’’
to a different receptor and/or otherwise
would have made emission reductions
beginning in 2012 due to the Transport
Rule).
EPA disagrees with comments
suggesting that emission reductions, and
resulting decreases in contribution, from
upwind states that are not ‘‘linked’’ to
a particular downwind receptor should
be accounted for in the 2014 AQAT
analysis of that receptor. EPA decided to
assume reductions only from linked
states when analyzing each receptor
because EPA is performing a statespecific analysis to support a
determination of the amount of each
upwind state’s responsibility for air
quality problems at the downwind
receptors that it significantly affects. If
the AQAT analysis were to assume
emissions reductions in other nonlinked states, the AQAT analysis would
then contradict the first step of our twothe 2012 base case nonattainment and maintenance
receptors analyzed, and the AQAT estimates closely
tracked CAMx-modeled concentrations at those
receptors under the Transport Rule remedy. The
paired AQAT-estimated and CAMx-modeled
concentrations were found to be highly correlated
with an R2 value of 0.997. As a result, EPA is
confident that AQAT’s estimates of impacts on
sulfate concentrations at the varying levels of SO2
emission reductions analyzed provide a technically
valid and sound basis for the Agency’s selection of
the final rule’s emission reductions necessary to
eliminate (or make meaningful progress toward
eliminating) significant contribution and
interference with maintenance for the PM2.5
NAAQS considered in this rulemaking. Further
details on the comparison of CAMx and AQAT
results can be found in the Significant Contribution
and State Emission Budgets Final Rule TSD.
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Fmt 4701
Sfmt 4700
step approach to defining significant
contribution to nonattainment and
interference with maintenance. Under
EPA’s two-step approach, only a state
that (1) contributes a threshold amount
or more to a particular downwind state
receptor’s air quality problem, and (2)
has emission reductions available at the
selected cost threshold can be deemed
to have responsibility to reduce its
emissions to improve air quality at that
downwind receptor. EPA believes that
the commenters’ suggested approach
would not qualify as a state-specific
approach for determining upwind state
responsibility for downwind air quality
problems.
Because EPA is relying on the CAMx
estimate of nitrate concentrations from
the AQAT calibration scenario, the
response in nitrate to NOX reductions at
a cost threshold of $500/ton is present
in each SO2 cost threshold scenario
analyzed.
EPA determines the cumulative air
quality improvement that can be
expected at a particular downwind
receptor by multiplying each upwind
state’s percent SO2 emission reduction
by its calibrated receptor specific sulfate
response factor and summing the
sulfate, nitrate, and other PM2.5
components (also taken from the 2014
CAMx AQAT calibration scenario).
3. Air Quality Assessment Results
The results of EPA’s air quality
assessment of the cost threshold
scenarios focus on air quality metrics
including, but not limited to, average air
quality improvement at receptors with
2012 base case nonattainment and
maintenance exceedances and an
evaluation of estimated receptor design
values against annual and 24-hour PM2.5
standards. See ‘‘Significant Contribution
and State Emission Budgets Final Rule
TSD’’ for more details.
In EPA’s air quality analysis of each
downwind receptor, all air quality
improvements are measured relative to
the ‘‘AQAT base case.’’ This base case
reflects AQAT’s estimated PM2.5
concentrations under base case 2014
SO2 emissions. The AQAT base case
itself is not used for any decision points
and only serves as an appropriate
starting point for comparison of air
quality improvements at SO2 cost
thresholds. EPA ensures internal
analytic consistency by comparing all
air quality improvements at analyzed
SO2 cost thresholds to the AQAT base
case.
Regarding average air quality
improvement at exceeding 2012 base
case receptors, EPA identified 41
receptors with nonattainment or
maintenance problems in the 2012 base
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case. EPA assessed the cumulative
reduction in 24-hour PM2.5 maximum
design value at each increasing SO2 cost
threshold from the maximum design
value from the AQAT base case, and
averaged the reduction across the 41
receptors. The results of this assessment
indicate diminishing incremental
returns to 24-hour PM2.5 maximum
design value reduction as SO2 cost
threshold levels increase. EPA finds
reductions in maximum design value of
4.28 μg/m3 at $500; 4.98 μg/m3 at
$1,600; 5.33 μg/m3 at $2,300; 5.46 μg/m3
at $2,800; 5.60 μg/m3 at $3,300; and 6.08
μg/m3 at $10,000. These results are
provided in table VI.C–1.
Additionally, EPA evaluated the
AQAT estimated 2014 average and
maximum design values for these
receptors at each cost threshold against
the annual and 24-hour PM2.5 standards.
EPA determined the estimated number
Average air qual- of receptors with nonattainment or
ity improvement maintenance problems at $500/ton cost
at exceeding
threshold of NOX and each of the cost
receptors in 2012
threshold scenarios assessed for SO2.
base case
(μg/m3)
These results are provided in table
VI.C–2 in terms of the number of
4.28 receptors and the number of
4.98
5.33 nonattainment areas containing these
5.46 receptors.
TABLE VI.C–1—AVERAGE 2014 AIR
QUALITY IMPROVEMENT AT RECEPTORS WITH 2012 BASE CASE NONATTAINMENT
AND
MAINTENANCE
PROBLEMS
Group 1 state SO2 cost
per ton threshold
$500 ..................................
$1,600 ...............................
$2,300 ...............................
$2,800 ...............................
$3,300 ...............................
$10,000 .............................
5.60
6.08
TABLE VI.C–2—RECEPTORS WITH NONATTAINMENT AND/OR MAINTENANCE EXCEEDANCES OF THE ANNUAL OR 24-HOUR
PM2.5 NAAQS IN 2014
Annual
nonattainment
Annual nonattainment or maintenance
24-hour
nonattainment
24-hour nonattainment or maintenance
Annual and 24-hour
nonattainment and
maintenance
Receptors
Receptors
SO2 cost threshold
Receptors
ebenthall on DSK6TPTVN1PROD with RULES2
$500 ...................................
$1,600 ................................
$2,300 ................................
$2,800 ................................
$3,300 ................................
$10,000 ..............................
Areas
1
1
0
0
0
0
1
1
0
0
0
0
In the proposal, EPA evaluated
whether the imposition of the rule’s
upwind emission reduction
requirements could cause changes in
operation of electric generating units in
states not regulated under the proposal.
EPA recognized that such changes could
lead to increased emissions in those
states, potentially affecting whether they
would meet or exceed the 1 percent
contribution thresholds used to identify
linkages between upwind and
downwind states. Such shifting of
emissions between states may occur
because of the interconnected nature of
the country’s energy system (including
both the electricity grid as well as coal
and natural gas supplies).
Using updated emissions and air
quality information developed for the
final rule, EPA’s IPM modeling found
that of the states not covered in the final
rule for PM2.5, Arkansas, Colorado,
Louisiana, Montana, and Wyoming are
all projected to have SO2 emission
increases above 5,000 tons in 2014 with
the rule in effect. EPA analysis shows
the SO2 emission increases result from
expected shifts to higher sulfur coal in
these states. Using AQAT, a state-level
assessment of these emission increases
relative to the state specific
contributions to downwind receptors
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Receptors
Areas
1
1
1
1
1
1
Receptors
1
1
1
1
1
1
Areas
2
2
1
1
1
1
(where available) indicates that
projected increases in the SO2 emissions
would not increase any of these states’
contributions to an amount that would
meet or exceed the 0.15 μg/m3 or 0.35
μg/m3 thresholds for annual and
24-hour PM2.5, respectively. For this
reason, EPA has determined that it is
not necessary to include these
additional states in the Transport Rule
as a result of the effects of the rule itself
on SO2 emissions in uncovered states.
See ‘‘Significant Contribution and State
Emission Budgets Final Rule TSD’’ in
the docket for this rulemaking for more
details.
D. Multi-Factor Analysis and
Determination of State Emission
Budgets
EPA used the cost, emission, and air
quality information described in the
previous sections to perform its multifactor analysis. By looking at different
‘‘cost thresholds’’—places where there
was a noticeable change on the cost
curve because emission reductions
occur—and examining the
corresponding impact on air quality,
EPA identified the amount of emissions
that represent significant contribution to
nonattainment and interference with
maintenance within each state. After
quantifying this amount of emissions,
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2
1
1
1
1
9
8
6
5
5
3
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6
5
4
4
4
3
9
8
6
5
5
3
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6
5
4
4
4
3
EPA established state ‘‘budgets’’ which
represent the remaining emissions for
the state in an average year (step 4).
For states covered by the rule for
PM2.5, EPA calculated annual NOX and
annual SO2 budgets. For states covered
by the rule for ozone, EPA calculated
ozone-season NOX budgets. This section
explains the multi-factor assessment
and how EPA used this assessment to
determine state-specific budgets.
1. Multi-Factor Analysis (Step 3)
a. Overview
As described in section VI.B, EPA
examined how different cost thresholds
impacted emissions in states with air
quality contributions that meet or
exceed specific air quality thresholds, as
discussed in section V.D of this
preamble. Section VI.C summarizes the
estimated air quality impacts in 2014 of
these emission levels at downwind
receptors, including estimates of their
nonattainment and maintenance status
(see ‘‘Significant Contribution and State
Emission Budgets Final Rule TSD’’ for
more details). From these two steps,
EPA evaluated the interaction between
upwind emissions at different cost
levels and air quality at downwind
receptors to identify ‘‘significant cost
thresholds.’’ These cost thresholds are
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based on air quality considerations
(such as the cost at which the air quality
assessment analysis projects large
numbers of downwind site maintenance
and nonattainment problems would be
resolved) or cost criteria (such as a cost
where large emissions reductions occur
because a particular technology is
widely implemented at that cost). EPA
examined each cost threshold and then
used a multi-factor assessment to
determine which serve as cost
thresholds that eliminate significant
contribution to nonattainment and
interference with maintenance for
upwind states. Air quality
considerations in the assessment
include, for example, how much air
quality improvement in downwind
states results from upwind state
emission reductions at different levels;
whether, considering upwind emission
reductions and assumed local (in-state)
reductions, the downwind air quality
problems would be resolved; and the
components of the remaining
downwind air quality problem (e.g.,
whether it is a predominantly local or
in-state problem, or whether it still
contains a large upwind component).
Cost considerations include, for
example, how the cost per ton of
emission reduction compares with the
cost per ton of existing federal and state
rules for the same pollutant; whether
the cost per ton is consistent with the
cost per ton of technologies already
widely deployed (similar to the highlycost-effective criteria used in both the
NOX SIP Call and CAIR); and what cost
increase is required to achieve
additional meaningful air quality
improvement.
The specific cost per ton thresholds
selected as a basis for identifying
significant contribution to
nonattainment and interference with
maintenance in this rulemaking apply
only to the determinations made in this
rule and do not establish any precedent
for future EPA actions under section
110(a)(2)(D)(i)(I) or any other section of
the CAA. EPA’s selection of specific
cost thresholds in the context of this
rulemaking relies on current analyses of
the cost of available emission
reductions, the pattern of interstate
linkages for pollution transport, and the
downwind air quality impacts
specifically related to the 1997 ozone
NAAQS, the 1997 annual PM2.5
NAAQS, and the 2006 24-hour PM2.5
NAAQS. In addition and as explained
below, the selection of the threshold for
ozone-season NOX was influenced by
the limited scope of this rule. Any or all
of these variables used to identify
specific cost thresholds are subject to
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change. Thus, EPA may use different
cost thresholds in future actions, even if
those actions relate to the same NAAQS
addressed in this rule.
b. Cost Thresholds Examined and
Selected for Ozone-Season NOX
In the proposal, EPA examined
various cost thresholds for ozone season
NOX and identified a cost threshold
with rapidly diminishing returns at
$500/ton. EPA observed that moving
beyond the $500 cost threshold up to a
$2,500 cost threshold would result in
only minimal additional ozone season
NOX emission reductions and would
likely bypass less expensive non-EGU
emission reduction opportunities (75 FR
45281). EPA noted that for greater costs
the curves did not include all available
reductions as they do not include nonEGU reductions (75 FR 44286). In the
proposal, EPA noted the timely
promulgation and implementation of
this rule is responsive to the Court’s
remand of CAIR, will accelerate critical
air quality improvement, and more
effectively address the mandate of CAA
section 110(a)(2)(D) to address
significant contribution to
nonattainment and interference with
maintenance as expeditiously as
practicable. EPA did not want to risk
delaying air quality benefits available
from EGU emission reductions,
particularly those emission reductions
which eliminate significant contribution
to nonattainment and interference with
maintenance for many receptors, while
the Agency conducts additional analysis
to support subsequent transport-related
rulemakings including coverage of nonEGU sources (75 FR 45285).
EPA received comments suggesting
that it consider cost thresholds higher
than $500/ton as reductions beyond the
proposed $500/ton cost threshold were
needed to fully resolve nonattainment
and maintenance issues in downwind
states analyzed at proposal. Some of
these comments suggested EPA should
include non-EGUs as they consider the
higher cost thresholds, others suggested
EPA continue to exclude non-EGU
sources in this rulemaking.
In response to those comments that
suggested EPA explore higher cost
thresholds because nonattainment and
maintenance was not fully resolved,
EPA first notes that CAA section 110
(a)(2)(D)(i)(I) only requires the
elimination of emissions that
significantly contribute to
nonattainment or interfere with
maintenance of the NAAQS in other
states. Section 110(a)(2)(D)(i)(I) focuses
exclusively on the transport component
of nonattainment and maintenance
problems. Section 110(a)(2)(D)(i)(I) does
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not shift to upwind states the
responsibility for ensuring that all areas
in other states attain the NAAQS. As
such, the mandate of section
110(a)(2)(D)(i)(I) is not to ensure that
reductions in upwind states are
sufficient to bring all downwind areas
in to attainment, it is simply to ensure
that all significant contribution to
nonattainment and interference with
maintenance is eliminated. Thus, the
presence of residual nonattainment or
maintenance areas does not, by itself,
signify a failure to satisfy the
requirements of 110(a)(2)(D)((i)(I).
Furthermore, as noted in section VI.A,
EPA is finalizing coverage only for the
EGU emission source-sector category in
this rulemaking. EPA has not included
non-EGU sources in this final
rulemaking. EPA remains convinced
that timely promulgation and
implementation of this rule is
responsive to the Court’s remand of
CAIR.
To the extent that significant
contribution is not eliminated for the
1997 ozone NAAQS standard at the
$500/ton cost threshold, EPA is not
addressing in this rulemaking whether a
cost threshold greater than $500/ton is
justified for some upwind states and
downwind receptors. EPA believes it
can best serve these states where
concerns persist regarding projected
nonattainment or maintenance of the
1997 ozone NAAQS by quickly
finalizing this rule and seeking further
non-EGU reductions in subsequent
rulemakings. Table VI.B–2 illustrates
the small amount of EGU reductions
available as cost threshold increases
above $500/ton. The ozone-season NOX
reductions available in the Transport
Rule states between the $500/ton and
$1,000/ton cost thresholds amount to
less than 3,000 tons. EPA believes that
potentially substantial non-EGU ozoneseason NOX reductions become
available approaching the $1,000/ton
cost threshold. EPA emphasized this in
the proposal, noting that the cost curves
for ozone season NOX did not reflect all
available reductions as they do not
include non-EGU reductions (75 FR
45286). For these reasons, EPA did not
consider cost thresholds greater than
$500/ton.
EPA did not consider cost thresholds
below $500/ton for ozone-season NOX.
$500/ton is a reasonable threshold
representing a significant amount of
lowest-cost NOX emission reductions
from EGUs, largely accruing from the
installation of combustion controls,
such as low-NOX burners, and
constitutes a reasonable cost level for
operation of existing NOX controls such
as SCRs. EPA believes it would be
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inappropriate for a state linked to
downwind nonattainment or
maintenance areas to stop operating
existing pollution control equipment
(which would increase their emissions
and contribution). This is increasingly
likely to occur at cost thresholds lower
than $500/ton. Therefore, EPA did not
find cost thresholds lower than $500/
ton for ozone-season NOX to be
reasonable for development of the
Transport Rule cost curves.
As discussed in section III of this
preamble, EPA intends to finalize
reconsideration of the March 2008
ozone NAAQS in the summer of 2011
and to expeditiously propose a
transport-related action to address any
necessary upwind state control
responsibilities with respect to that
reconsidered NAAQS.
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c. Cost Thresholds Examined and
Selected for Annual NOX
Following the assessment of the cost
curves in section IV.B and the air
quality modeling of the AQAT
calibration scenario using CAMx, EPA
identified a single cost threshold at
$500/ton for annual NOX. Beyond
requiring the year-round operation of
existing post-combustion NOX controls
and other reductions modeled at $500/
ton threshold, EPA observed a
limitation in available low-cost annual
NOX reductions from EGUs.
Approximately 7,000 tons of annual
NOX reductions were available from
EGUs between the $500/ton and the
$1,000/ton cost thresholds (See Table
VI.B.–1). Furthermore, above the $500/
ton threshold, similar to ozone-season
NOX cost curves, the annual NOX cost
curves do not include all available
reductions as they do not include nonEGU reductions. EPA analysis suggests
that while NOX emission reductions
lead to reductions in PM2.5, SO2
reductions are generally more costeffective than NOX reductions at
reducing PM2.5 (75 FR 45281). In part,
for these reasons, EPA’s multi-factor
assessment suggested that the $500/ton
cost threshold for annual NOX in
concert with the cost thresholds
identified for SO2 were the appropriate
cost thresholds for eliminating
significant contribution to
nonattainment and interference with
maintenance. EPA finds in the final
Transport Rule that the $500/ton cost
threshold for annual NOX, in concert
with the SO2 cost threshold selected
below, successfully eliminates
significant contribution to
nonattainment and interference with
maintenance for the 1997 annual PM2.5
NAAQS and the 2006 24-hour PM2.5
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NAAQS in the states covered by this
Rule for PM2.5.
The reasons for not considering cost
thresholds lower than $500/ton for
annual NOX are the same as those
identified for not doing so for ozoneseason NOX. In addition to its PM2.5
reduction benefits, annual NOX control
at the $500/ton threshold can help to
reduce nitrate replacement in the
atmosphere. As explained earlier,
nitrate replacement happens when SO2
emissions reductions successfully
reduce ammonium sulfate (a component
of PM2.5) but provoke a PM2.5 rebound
effect by freeing up additional ammonia
to form ammonium nitrate (another
component of PM2.5).
d. Cost Thresholds Examined and
Selected for SO2
EPA first assessed the downwind air
quality impacts of emission reductions
modeled at the $500/ton threshold in all
states found to be linked to downwind
sites for PM2.5 transport, as well as in
the states hosting those downwind sites.
The air quality assessment tool
projected that those reductions do not
fully resolve nonattainment and
maintenance problems with the PM2.5
standards for certain areas to which the
following states are linked: Illinois,
Indiana, Iowa, Kentucky, Maryland,
Michigan, Missouri, New Jersey, New
York, North Carolina, Ohio,
Pennsylvania, Tennessee, Virginia, West
Virginia, and Wisconsin. EPA
proceeded to analyze available 2014
emission reductions at higher cost
thresholds from these states, collectively
referred to as Group 1 states for SO2
control.
For Group 2 states, the air quality
assessment tool projected that the SO2
reductions at this first cost threshold
assessed would resolve the
nonattainment and maintenance
problems for all of the areas to which
the following states are linked:
Alabama, Georgia, Kansas, Minnesota,
Nebraska, South Carolina, and Texas.
EPA thus finds that these states’
significant contribution is eliminated at
the $500 per ton level in 2014; they are
collectively referred to as Group 2 states
for SO2 control. Because their
significant contribution is eliminated at
this stringency of control, EPA did not
analyze higher cost thresholds for Group
2 states.
The states in Group 1 and Group 2 are
rationally grouped considering air
quality and cost. EPA determined that it
would not be appropriate to assign the
same cost threshold to Group 2 and
Group 1 states because a significantly
lower cost threshold was sufficient to
resolve air quality problems at all
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48257
downwind receptors linked to the
Group 2 states. Although states are
linked to different sets of downwind
receptors, EPA analysis indicated that
the cost threshold needed to resolve
downwind air quality problems varied
only to a limited extent among states
within Group 1 and among states within
Group 2. It did, however, vary greatly
between the Group 1 and Group 2 states.
The ruling of the DC Circuit in Michigan
v. EPA, 213 F.3d 663, 679–80 (D.C. Cir.
2000), accepting EPA’s prior use of a
transport remedy with uniform controls,
supports EPA’s decision to use a
uniform cost threshold for a group of
states.
As discussed in section VI.B, the cost
threshold for Group 1 states was
examined at escalating levels in 2014 (it
remained at $500/ton for Group 2
states). EPA examined emissions at SO2
cost thresholds of $500, $1,600, $2,300,
$2,800, $3,300, and $10,000/ton for
Group 1 states in 2014. The higher SO2
marginal costs were only imposed in
Transport Rule states starting in 2014,
by which time the advanced pollution
control retrofits induced at those higher
cost thresholds could be installed. (See
section VI.D.2 for EPA’s assessment and
decisions regarding SO2 budget
formation in Group 1 states in 2014.)
EPA observed some degree of
additional air quality benefit at
downwind receptors across all of the
cost thresholds examined for SO2, but
significant air quality outcomes were
achieved at the $2,300/ton cost
threshold. The $2,300/ton threshold is
projected to resolve the last remaining
nonattainment area for the annual PM2.5
standard (Liberty-Clairton),46 and it also
is projected to resolve the
nonattainment and maintenance
problems with the 24-hour PM2.5
standard at 1 monitor in the Detroit area
and resolve the maintenance problems
in the Cleveland area. There were
significant air quality improvements at
this level in connection with
widespread deployment of pollution
control technology, while the cost
impacts remained reasonable.
Moving beyond $2,300/ton to the
$2,800/ton and $3,300/ton thresholds,
EPA projected notably smaller air
quality improvements compared to
those projected when moving from the
$1,600/ton threshold to the $2,300/ton
threshold. EPA also projected no
ultimate change in the 24-hour PM2.5
46 AQAT results indicated that one receptor in the
Liberty-Clairton area continued to have
maintenance problems with the annual PM2.5
standard. However, final air quality modeling
results (described in section VIII.B) indicated that
this maintenance problem was resolved for this
receptor under the final Transport Rule.
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attainment status of the remaining
nonattainment area (Liberty-Clairton) or
three remaining maintenance areas
(Chicago,47 Detroit, and Lancaster).48 At
the same time, the total program cost
continued to increase by about the same
interval at each of these thresholds as it
had between the $1,600/ton and $2,300/
ton thresholds. EPA thus observed a
relatively lower cost-effectiveness of
downwind PM2.5 control via upwind
SO2 reductions beyond $2,300/ton for
the receptors linked to Group 1 states.
Table VI.D–1 and Figure VI.D–1
demonstrate this relationship between
cost of EGU SO2 control and downwind
PM2.5 concentration impacts, showing a
sustained diminishing of cost
effectiveness beyond the $2,300/ton
threshold. The $2,300/ton threshold in
this analysis is situated at the ‘‘knee-inthe-curve’’ area of cost-effectiveness for
addressing downwind PM2.5
concentrations with SO2 reductions,
beyond which point the air quality gains
per dollar spent on additional
reductions are much smaller. This
relationship is demonstrative of the
economic potency of SO2 reductions at
each cost threshold to address the PM2.5
concentrations at linked receptors in
this analysis.
TABLE VI.D–1—COST-EFFECTIVENESS OF GROUP 1 STATE SO2 REDUCTIONS a FOR DOWNWIND PM2.5 CONTROL
Additional system cost
expended
(2007$, billions)
SO2 cost threshold
$500 .............................................................................................
$1,600 ..........................................................................................
$2,300 ..........................................................................................
$2,800 ..........................................................................................
$3,300 ..........................................................................................
$10,000 ........................................................................................
Average PM2.5 air
quality improvement
(μg/m3) b
0.22
0.82
1.35
1.94
2.36
3.61
3.27
3.86
4.22
4.37
4.50
4.99
Air quality cost-effectiveness (average μg/m3 reduced per billion
$ expended)
14.74
4.70
3.11
2.25
1.91
1.38
a Downwind
PM2.5 improvement based on SO2 reductions from states ‘‘linked’’ to specific receptors. See section VI.C.
as the reduction in maximum design value for the 24-hour PM2.5 NAAQS from AQAT base case to each SO2 threshold for receptors with remaining nonattainment and maintenance exceedances at the $500/ton threshold, averaged across these receptors.
b Measured
concerns with the annual PM2.5
standard and is projected to remain in
nonattainment of the 24-hour PM2.5
standard, while the Chicago 49 and
Lancaster areas are still projected to
have residual maintenance problems
47 This area is not currently designated as
nonattainment for the 24-hour PM2.5 standard. EPA
is portraying the receptors and counties in this area
as a single 24-hour maintenance area based on the
annual PM2.5 nonattainment designation of
Chicago-Gary-Lake County, IL-IN.
48 AQAT results indicated that two receptors in
the Detroit area continued to have maintenance
problems with the 24-hour PM2.5 standard.
However, final air quality modeling results
(described in section VIII.B) indicated that only one
receptor continued to have maintenance problems
in this area for this standard under the final
Transport Rule.
49 This area is not currently designated as
nonattainment for the 24-hour PM2.5 standard. EPA
is portraying the receptors and counties in this area
as a single 24-hour maintenance area based on the
annual PM2.5 nonattainment designation of
Chicago-Gary-Lake County, IL-IN.
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Furthermore, even at the $10,000/ton
cost threshold, AQAT still projects
Liberty-Clairton to face maintenance
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with the 24-hour PM2.5 standard. EPA
projected that even total elimination of
EGU SO2 emissions (no matter the cost)
would not be able to resolve either
nonattainment of the 24-hour PM2.5
standard in the Liberty-Clairton area or
the residual maintenance concerns with
that standard in Lancaster County. EPA
thus finds that other PM2.5 strategies,
including local reductions of other
PM2.5 precursors, are important to
consider for remaining nonattainment
and maintenance areas to seek further
improvements in PM2.5 concentrations.
Considering both air quality and cost,
EPA’s multi-factor analysis indicated
$2,300 per ton as an appropriate cost
threshold for SO2 in the Group 1 states.
EPA believes the analyzed cost
thresholds lower than $2,300/ton were
not appropriate for SO2 control in the
Group 1 states under the Transport Rule
for the following reasons:
• Downwind air quality impacts up to
the $2,300 threshold are significant.
Moving up to $2,300/ton successfully
resolves all downwind nonattainment of
the annual and 24-hour PM2.5 standards
except for the Liberty-Clairton receptor
in Allegheny county with respect to
24-hour PM2.5, which EPA has noted is
heavily influenced by a local source of
organic carbon (75 FR 45281).
• Upwind emission reductions
available up to $2,300/ton are highly
cost-effective compared with similar
regulations.
• The emission reductions up to this
threshold are achievable with
widespread deployment of controls that
can be installed at power plants by
2014.
• As stated at proposal, EPA finds it
reasonable to require a substantial level
of control of upwind state emissions
that significantly contribute to
nonattainment or maintenance problems
in another state. The $2,300/ton cost
threshold is comparable to EPA’s survey
of local non-EGU SO2 reduction
opportunities in the PM2.5 NAAQS RIA,
which range in cost from just above
$2,300/ton to over $16,000/ton (2007 $).
EPA thus finds it reasonable to seek
EGU SO2 reductions up to $2,300/ton
(rather than at a lower cost threshold) in
the states linked to receptors with
ongoing attainment and maintenance
concerns with the PM2.5 NAAQS.
EPA believes the analyzed cost
thresholds above $2,300/ton were not
appropriate for SO2 control in the Group
1 states under the Transport Rule for the
following reasons:
• As noted above, AQAT suggests
reductions up to $2,300/ton were able to
resolve all projected downwind
nonattainment of the annual and
24-hour PM2.5 NAAQS, with the sole
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exception of projected nonattainment of
the 24-hour PM2.5 standard at a receptor
in Liberty-Clairton. It is well-established
that, in addition to being impacted by
regional sources, the Liberty-Clairton
area is significantly affected by local
emissions from a sizable coke
production facility and other nearby
sources, leading to high concentrations
of organic carbon in this area.50 EPA
finds that the remaining PM2.5
nonattainment problem is
predominantly local and therefore does
not believe that it would be appropriate
to establish a higher cost threshold
solely on the basis of this projected
ongoing nonattainment of the 24-hour
PM2.5 standard at the Liberty-Clairton
receptor.
• Approximately 70 percent of base
case SO2 emissions from Group 1 states
were eliminated at the $2,300/ton cost
threshold, leaving a decreasing amount
of emission reductions available at each
increased cost threshold beyond $2,300/
ton.
• Additional EGU SO2 reductions
available from EGUs beyond the $2,300/
ton threshold level realize significantly
less improvement in downwind PM2.5
concentrations per dollar spent to
impact receptors linked to Group 1
states. In other words, the costeffectiveness of controlling EGU
emissions in Group 1 states to improve
downwind PM2.5 concentrations at the
linked receptors is notably diminished
beyond the $2,300/ton threshold in this
analysis. See Figure VI.D–1.
• EGUs are by far the largest source
category for SO2 emissions. This
analysis shows that reductions of EGU
SO2 emissions up to the $2,300/ton cost
threshold were significantly more costeffective for improving downwind PM2.5
concentrations than further such
reductions (beyond the $2,300/ton cost
threshold) would be to address the
remaining PM2.5 maintenance concerns.
EPA’s analysis also shows that these
maintenance concerns cannot be fully
resolved even with complete
elimination of all remaining EGU SO2
emissions, no matter the cost. EPA finds
that other PM2.5 precursor emission
reductions, particularly those from local
sources will be critical for states in these
remaining areas to consider for
controlling PM2.5 concentrations with
respect to maintenance of the 2006
24-hour PM2.5 NAAQS.
In summary, the appropriate cost
thresholds for each state were identified
through the multi-factor assessment.
This assessment included both cost and
50 https://www.epa.gov/pmdesignations/2006
standards/final/TSD/tsd_4.0_4.3_4.3.3_r03_PA_
2.pdf.
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air quality considerations. As explained
above, the ozone-season NOX threshold
was determined to be $500/ton for all
states required to reduce ozone-season
NOX, with residual nonattainment and
maintenance concerns to be addressed
in a future rulemaking addressing a
broader set of source categories for
additional cost-effective reductions. For
PM2.5, the appropriate cost threshold for
each state was determined to be either
the level at which nonattainment and
maintenance issues were completely
resolved in downwind states to which
the state is linked, the level where
remaining nonattainment and
maintenance issues are primarily local,
or where we found greatly diminished
improvements in air quality occurring if
EPA moved further up the cost curve.
This assessment yielded a cost
threshold of $2,300/ton on SO2 for
Group 1 states starting in 2014 ($500/
ton in 2012), a cost threshold of $500/
ton on SO2 for Group 2 states, and a cost
threshold of $500/ton on annual NOX
for all states required to reduce
emissions for purposes of the annual or
24-hour PM2.5 NAAQS in this rule.
As explained above, none of these
specific cost thresholds establish any
precedent for the cost per ton stringency
of reductions EPA may require in future
transport-related rulemakings; these
specific cost thresholds are based on
current analyses of air quality and cost
of emission reductions with respect to
the NAAQS considered in this
rulemaking and thus would not be
relevant to future rulemakings (which
would consider updated information) or
rulemakings with respect to different
NAAQS. In particular, EPA
acknowledges that additional action
EPA will require in a subsequent
rulemaking to address significant
contribution to nonattainment and
interference with maintenance of the
2008 ozone NAAQS (once
reconsideration is finalized) is very
likely to require a higher cost per ton
stringency of ozone-season NOX control
applied to a broader set of source
categories from upwind states than
found to be appropriate for this
rulemaking.
2. State Emission Budgets (Step 4)
a. Budget Methodology
EPA used the multi-factor assessment
to identify, for each state, the cost
threshold that should be used to
quantify that state’s significant
contribution. As described above, in the
context of this rulemaking EPA
identified a cost threshold of $500/ton
for ozone-season NOX control for all
states required to reduce ozone-season
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NOX emissions for purposes of the 1997
ozone NAAQS in this rule. EPA also
identified a cost threshold of $500/ton
for annual NOX control for all states
required to reduce annual NOX
emissions for purposes of the annual or
24-hour PM2.5 NAAQS in this rule.
Finally, EPA identified a cost threshold
of $500/ton of SO2 starting in 2012 for
all states required to reduce SO2
emissions for purposes of the annual or
24-hour PM2.5 NAAQS in this rule, and
emission reductions available at cost
thresholds of $500/ton for annual NOX
in 2012 and 2014, $500/ton for SO2 in
2012, and $2,300/ton for SO2 in 2014.
The total SO2 and NOX projected at
these cost levels in that state in those
years represents that state’s emissions
once significant contribution to
nonattainment or interference with
maintenance downwind for the relevant
PM2.5 NAAQS has been eliminated.
$2,300/ton for the Group 1 states
starting in 2014.
EPA used these cost thresholds from
the multi-factor analysis to quantify
each state’s emissions that significantly
contribute to nonattainment or interfere
with maintenance downwind. For
example, for a Group 1 state, EPA
modeling of the cost threshold conveys
emission reductions available in each
covered state from operation of existing
pollution controls as well as all
TABLE VI.D–2—EXAMPLE OF EMISSION REDUCTIONS AND BUDGET FORMATION IN PENNSYLVANIA FOR ANNUAL SO2 AND
NOXa
Final cost
threshold
B
2012 ..........................................
SO2 ...........................................
NOX ..........................................
SO2 ...........................................
NOX ..........................................
2014 ..........................................
Remaining
emissions at
cost thresholds
(1,000 tons)
Emissions
eliminated
(1,000 tons)
C
A
Base case
emissions
(1,000 tons)
D
E
F
$500
500
2,300
500
493
129
507
132
279
120
112
119
215
9
395
13
ebenthall on DSK6TPTVN1PROD with RULES2
a Note: In this table, emissions are shown for fossil-fuel-fired EGUs > 25 MW (i.e., those units likely covered by the Transport Rule). Table
VI.D.2 illustrates how budgets are derived from the elimination of significant contribution for the state of Pennsylvania. Column C illustrates the
cost thresholds applied in the costing run that was ultimately identified as the final cost threshold in the multi-factor analysis. Column D shows
the base case emissions for the identified pollutant in the identified time period. Column E shows the emission levels that result when the cost
thresholds identified in column C are applied. Because this is the cost threshold identified through the multi-factor analysis and the point where
all significant contribution to nonattainment and interference with maintenance has been addressed for the PM2.5 NAAQS—state budgets are
based on these emission levels. The final column illustrates the emission reductions for the state in an average year (before accounting for
variability).
EPA’s modeling of a state’s SO2 and
annual NOX emission levels (from
fossil-fired EGUs > 25 MW) at the
relevant cost thresholds in each state
reflect that state’s emissions from
covered sources after the removal of
significant contribution to
nonattainment and interference with
maintenance of the PM2.5 NAAQS
considered in this rulemaking. As these
state emission levels reflect the removal
of significant contribution and
interference with maintenance, they are
reasonable levels on which to determine
state budgets. Consequently, EPA based
state budget levels on the state level
emissions that remained at the cost
threshold. Each state’s budget
corresponds to its emission level
following the elimination of significant
contribution to nonattainment and
interference with maintenance in an
average year (before taking year-to-year
variability into account, as discussed in
section VI.E below). Therefore, the
implementation and realization of these
budgeted emission levels leads to the
elimination of significant contribution
to nonattainment and interference with
maintenance and EPA meets the
statutory mandate of section
110(a)(2)(D)(i)(I) with respect to the
1997 annual PM2.5 NAAQS and the 2006
24-hour PM2.5 NAAQS.
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EPA’s establishment of state budgets
for ozone-season NOX control follow the
same methodology as described above
for SO2 and annual NOX.
Implementation of these ozone-season
NOX budgets reflects the elimination of
significant contribution to
nonattainment and interference with
maintenance of the 1997 ozone NAAQS
for 15 states, whereas 11 other states’
ozone-season NOX budgets reflect
meaningful progress toward (but may
not reflect full completion of) this
elimination under the mandate of
section 110(a)(2)(D)(i)(I). See section III
for lists of states.
This approach to basing budgets on
projected state level emissions used in
the multi-factor analysis is identical to
the approach used in the proposal for
determining 2014 SO2 budgets for
Group 1 states. EPA is extending this
approach more broadly in the final
Transport Rule to create state budgets
for ozone-season NOX, annual NOX, and
SO2 in all relevant states in both 2012
and 2014. In the proposal EPA used a
more complex approach based on a
comparison of historic and projected
unit-level emissions (further adjusted
for operation of existing controls) in
each state to create 2012 state budgets
for ozone-season NOX, annual NOX, and
Group 2 SO2. At the time of proposal,
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EPA believed that historic 2009
emissions data were in some cases more
representative of expected emissions in
2012 than pure modeling projections
made at the time (75 FR 45290).
However, following the proposal EPA
has made significant updates to the IPM
model for projecting EGU emissions,
including specifically the adoption of
2009 historic data into its modeling
parameters directly. EPA also received
substantial public input following the
proposal on the model’s assumptions
and representation of individual units,
which allowed EPA to improve its 2012
and 2014 emission projections for states
under the cost thresholds considered.
These modeling updates diminish the
concerns EPA expressed at proposal that
2009 historic data may have offered for
some states a better proxy for 2012
emissions than model projections,
particularly now that EPA is
incorporating 2009 data directly in its
updated modeling projections. Given
these updates to the model in response
to public comment, EPA believes it is
more appropriate for the final rule to
use a consistent approach based on
projected state level emissions for all
state budgets, as was done for Group 1
SO2 budgets in 2014 at proposal. EPA
received significant comment
supporting the use of the model to
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project state-level emissions for creating
budgets in this manner. EPA also
received comments that criticized the
proposal’s methodology for 2012
budgets for lack of transparency,
unnecessary complexity, and
inconsistency with the state-level
emission projections used in the air
quality modeling. EPA’s decision for the
final Transport Rule to consistently
apply across all pollutants the budget
methodology originally used for Group
1 SO2 budgets in 2014 addresses those
concerns.
This budget methodology for the final
rule uses projected state-level emissions
in 2012 and 2014 to set emission
budgets for those years on relevant
pollutants for that state to control under
the Transport Rule. EPA’s modeling
projects that some states have 2014
emissions that are lower than their 2012
projected emissions even as the same
cost threshold (e.g., $500/ton) is applied
in both years. This occurs in the annual
NOX, ozone-season NOX, and Group 2
SO2 program. As such, EPA’s
application of this budgeting
methodology results in a tightening of
budgets in states whose projected
emissions of that budgeted pollutant
decline from 2012 to 2014 as the cost
threshold is held constant.
There are two primary variables that
explain the decrease in emissions for
some states between 2012 and 2014 as
the cost threshold remains constant over
both time periods. First, even though
the cost threshold is constant between
2012 and 2014 for the programs noted
above, the cost threshold for SO2 Group
1 increases in 2014. This higher cost
threshold for Group 1 SO2 results in
obvious reductions in SO2 emissions in
the Group 1 states, but also may lower
the cost of certain related NOX
reductions in those states as well such
that they become newly available within
the $500/ton threshold. For example, if
a state increases natural gas generation
in response to the higher SO2 cost
threshold, such action also yields
additional annual and ozone-season
NOX emission reductions that are costeffective at the $500/ton NOX threshold.
Where the cost curve modeling shows
such additional cost-effective NOX
reductions in tandem with SO2 control,
EPA is therefore reducing those states’
2014 annual NOX and ozone-season
NOX budgets accordingly, so that those
budgets accurately reflect remaining
emissions from covered sources in those
states after the elimination of all
emissions that can be reduced up to the
relevant cost thresholds (e.g., $500/ton).
Second, some of these additional
reductions are driven by non-Transport
Rule variables. These are reductions that
occur due to state rules, consent
decrees, and other planned changes in
generation patterns that occur after
2012, but during or prior to 2014. For
example, EPA modeling reflects
emission reduction requirements under
provisions of a Georgia state rule that go
into effect after 2012 but before 2014.
These requirements involve the
installation and operation of specific
advanced pollution controls. These
source-specific requirements under a
legal authority unrelated to the
Transport Rule result in sharp
reductions in Georgia’s baseline
emission projections between 2012 and
2014. Even though the cost threshold for
NOX and for SO2 in Georgia is $500/ton
in both 2012 and 2014, EPA believes it
is important to establish separate NOX
and SO2 budgets that accurately reflect
the emissions remaining in Georgia (and
other states experiencing similar
reductions) after the elimination of
emissions that can be reduced up to the
Transport Rule remedy’s cost thresholds
(e.g., $500/ton) (see Table VI.D.3). It
illustrates a notable decrease between
the 2012 and 2014 state budgets for NOX
and SO2 in Georgia that is largely driven
by state rule requirements. If EPA did
not adjust 2014 budgets to account for
other emission reductions that would
occur even in the baseline, other sources
within the state would be allowed to
increase their emissions under the
unadjusted Transport Rule budgets to
48261
offset the emission reductions planned
under other requirements such as state
rules. Therefore, to prevent the
Transport Rule from allowing such
offsetting of emission reductions already
expected to occur between 2012 and
2014, EPA is establishing separate
budgets for 2012 and 2014 in the final
Transport Rule to capture emission
reductions in each state that would
occur for non-Transport Rule-related
reasons (i.e., in the base case) during
that time.
EPA’s modeling also projects that
other states would slightly increase
emissions from 2012 to 2014 even at the
same cost threshold, such as $500/ton.
There are two primary variables that
explain the increase in emissions for
these states between 2012 and 2014.
These increases are generally small in
magnitude. For annual and ozone
season NOX, they occur as a byproduct
of small changes in dispatch related to
changes in non-Transport Rule factors
(e.g., higher demand in 2014). For SO2,
they primarily occur in Group 2 states
and, in addition to the reasons given
above, are influenced by some
generation shifting from Group 1 to
Group 2 states as the Group 1 states
begin to face a higher cost threshold in
2014. EPA believes that allowing for
such emission growth in covered states
beyond 2012 would be inconsistent
with the Transport Rule’s identification
and elimination of significant
contribution to nonattainment and
interference with maintenance
beginning in 2012. Therefore, for any
covered state whose emissions of a
relevant pollutant are projected to
increase from 2012 to 2014 under the
relevant cost thresholds selected in the
multi-factor analysis described above,
EPA is finalizing that state’s 2014
emission budget to maintain the same
level of the 2012 emission budget,
thereby disallowing such an emission
increase that is inconsistent with the
110(a)(2)(D)(i)(I) mandate. Tables VI.D–
3 and VI.D–4 below list state emission
budgets.51
TABLE VI.D–3—SO2 AND ANNUAL NOX STATE EMISSION BUDGETS FOR ELECTRIC GENERATING UNITS BEFORE
ACCOUNTING FOR VARIABILITY *
[Tons]
SO2
NOX
Group
ebenthall on DSK6TPTVN1PROD with RULES2
2012–2013
Alabama ...........................................................
Georgia ............................................................
51 These budgets include minor technical
corrections to SO2 budgets in three states (KY, MI,
and NY) that were made after the impact analyses
for the final rule were conducted. EPA conducted
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2
2
2014 and beyond
216,033
158,527
sensitivity analysis confirming that these
differences do not meaningfully alter any of the
Agency’s findings or conclusions based on the
projected cost, benefit, and air quality impacts
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2012–2013
213,258
95,231
72,691
62,010
2014 and beyond
71,962
40,540
presented for the final Transport Rule. The results
of this sensitivity analysis are presented in
Appendix F in the final Transport Rule RIA.
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TABLE VI.D–3—SO2 AND ANNUAL NOX STATE EMISSION BUDGETS FOR ELECTRIC GENERATING UNITS BEFORE
ACCOUNTING FOR VARIABILITY *—Continued
[Tons]
NOX
SO2
Group
2012–2013
2014 and beyond
2012–2013
2014 and beyond
Illinois ...............................................................
Indiana .............................................................
Iowa ..................................................................
Kansas .............................................................
Kentucky ..........................................................
Maryland ..........................................................
Michigan ...........................................................
Minnesota .........................................................
Missouri ............................................................
Nebraska ..........................................................
New Jersey ......................................................
New York .........................................................
North Carolina ..................................................
Ohio ..................................................................
Pennsylvania ....................................................
South Carolina .................................................
Tennessee .......................................................
Texas ...............................................................
Virginia .............................................................
West Virginia ....................................................
Wisconsin .........................................................
1
1
1
2
1
1
1
2
1
2
1
1
1
1
1
2
1
2
1
1
1
234,889
285,424
107,085
41,528
232,662
30,120
229,303
41,981
207,466
65,052
5,574
27,325
136,881
310,230
278,651
88,620
148,150
243,954
70,820
146,174
79,480
124,123
161,111
75,184
41,528
106,284
28,203
143,995
41,981
165,941
65,052
5,574
18,585
57,620
137,077
112,021
88,620
58,833
243,954
35,057
75,668
40,126
47,872
109,726
38,335
30,714
85,086
16,633
60,193
29,572
52,374
26,440
7,266
17,543
50,587
92,703
119,986
32,498
35,703
133,595
33,242
59,472
31,628
47,872
108,424
37,498
25,560
77,238
16,574
57,812
29,572
48,717
26,440
7,266
17,543
41,553
87,493
119,194
32,498
19,337
133,595
33,242
54,582
30,398
Grand Total ...............................................
............................
3,385,929
2,135,026
1,245,869
1,164,910
Group 1 Total ............................................
............................
2,530,234
1,345,402
NA
NA
Group 2 Total ............................................
............................
855,695
789,624
NA
NA
Note: These state emission budgets apply to emissions from electric generating units covered by the Transport Rule Program. Group 1/Group
2 designations are only relevant for SO2 emissions budgets.
* The impact of variability on budgets is discussed in section VI.E.
ebenthall on DSK6TPTVN1PROD with RULES2
The District of Columbia is not
covered by the final Transport Rule. As
discussed in section V.D of this
preamble and as done for the Transport
Rule proposal, EPA combined
contributions projected in the air quality
modeling from Maryland and the
District of Columbia to determine
whether those jurisdictions collectively
contribute to any downwind
nonattainment or maintenance receptor
in amounts equal to or greater than the
1 percent thresholds. This modeling
confirmed that the combined
contributions exceed the air quality
threshold at downwind receptors for the
ozone, annual PM2.5, and 24-hour PM2.5
NAAQS considered. Both Maryland and
the District of Columbia are therefore
linked to these receptors.52 However,
the District of Columbia is not included
in the Transport Rule because, in the
second step of EPA’s significant
52 It is important to note that Maryland’s modeled
contributions in isolation were greater than the 1
percent threshold for all three of the NAAQS
considered at all of the same receptors for which
Maryland and DC were ‘‘linked,’’ and therefore EPA
would have considered Maryland ‘‘linked’’ to the
same set of downwind receptors even if the Agency
had treated Maryland’s contributions and the
District of Columbia’s contributions separately.
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contribution analysis, we concluded
that there are no emission reductions
available from EGUs in the District of
Columbia at the cost thresholds deemed
sufficient to eliminate significant
contribution to nonattainment and
interference with maintenance of the
NAAQS considered at the linked
receptors. At the time of this
rulemaking, EPA finds only one facility
with units meeting the Transport Rule
applicability requirements in the
District of Columbia. EPA’s projections
do not show any generation from this
facility to be economic under any
scenario analyzed (including the base
case), and the facility’s owners have also
announced plans to retire its units in
early 2012.53 Therefore, this unit is
projected to have zero emissions in
2012. As such, the total SO2 and NOX
emissions in the District of Columbia for
EGUs that meet the Transport Rule
applicability requirements is also
projected to be zero. It follows therefore,
that EPA did not identify any emission
reductions available at any of the cost
thresholds considered in the final rule’s
multi-factor analysis to identify
significant contribution to
nonattainment and interference with
maintenance. For this reason, EPA
concludes that no additional limits or
reductions are necessary, at this time, in
the District of Columbia to satisfy the
requirements of section 110(a)(2)(D)(i)(I)
with respect to the 1997 ozone, the 1997
PM2.5 and the 2006 PM2.5 NAAQS. EPA
is therefore neither establishing budgets
nor finalizing any FIPs for the District
of Columbia in this rule.
TABLE VI.D–4—OZONE SEASON NOX
STATE EMISSION BUDGETS FOR
ELECTRIC GENERATING UNITS BEFORE ACCOUNTING FOR VARIABILITY *
[Tons]
2012–2013
53 The
future retirement status of this D.C. facility
was also supported by its inclusion on PJM’s future
deactivation list. PJM further suggested that
reliability issues related to their retirement are
expected to be resolved by next year in time for its
planned retirement date. (See PJM pending
deactivation request in TR Docket.)
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Alabama ................
Arkansas ...............
Florida ...................
Georgia .................
Illinois ....................
E:\FR\FM\08AUR2.SGM
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31,746
15,037
27,825
27,944
21,208
2014 and
beyond
31,499
15,037
27,825
18,279
21,208
Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
TABLE VI.D–4—OZONE SEASON NOX
STATE EMISSION BUDGETS FOR
ELECTRIC GENERATING UNITS BEFORE ACCOUNTING FOR VARIABILITY *—Continued
[Tons]
2012–2013
2014 and
beyond
Indiana ..................
Kentucky ...............
Louisiana ..............
Maryland ...............
Mississippi ............
New Jersey ...........
New York ..............
North Carolina ......
Ohio ......................
Pennsylvania ........
South Carolina ......
Tennessee ............
Texas ....................
Virginia ..................
West Virginia ........
46,876
36,167
13,432
7,179
10,160
3,382
8,331
22,168
40,063
52,201
13,909
14,908
63,043
14,452
25,283
46,175
32,674
13,432
7,179
10,160
3,382
8,331
18,455
37,792
51,912
13,909
8,016
63,043
14,452
23,291
Total ...............
495,314
466,051
ebenthall on DSK6TPTVN1PROD with RULES2
Note: These state emission budgets apply
to emissions from electric generating units
covered by the Transport Rule Program.
Group 1/Group 2 designations are only relevant for SO2 emissions budgets.
* The impact of variability on budgets is discussed in section VI.E.
EPA notes that the NOX budgets for
five states linked to downwind ozone
receptors in the final Transport Rule are
equal to their projected 2012 base case
emissions. The five states are Arkansas,
Indiana, Louisiana, Maryland, and
Mississippi. These states are among
those found to meet or exceed the 1
percent contribution threshold for the
1997 ozone NAAQS at downwind
receptors and are thus ‘‘linked’’ to
downwind receptors. EPA therefore
evaluates, in the second step of its
significant contribution analysis, what
emission limits are necessary to ensure
that all emissions that constitute the
state’s significant contribution to
nonattainment and interference with
maintenance are prohibited. As
explained above, EPA decided to
require from all such states all
reductions available at the $500/ton cost
threshold. The five states identified
above do not appear to show EGU
ozone-season NOX reductions at the
$500/ton cost threshold relative to the
2012 base case projections (which do
not take into account reductions to be
made in other states as a result of this
rule). Therefore, EPA conducted further
analysis to evaluate whether such
reductions were available in these states
and whether emission limits are
necessary to prohibit these states from
significantly contributing to downwind
nonattainment or interfering with
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maintenance of the 1997 ozone NAAQS
in other states. (See the docket to this
rulemaking for the IPM run titled
TR_uncontrolled_ozone_states_Final.’’)
Specifically, EPA projected those
states’ ozone-season NOX emissions if
all other linked states (but not these five
states) were to make all available
reductions at the $500/ton threshold.
That analysis revealed that if emission
limits were not established for these five
states, ozone-season NOX emissions in
each of the states would increase
(beyond the 2012 base case emission
projections), due to interstate shifts in
electricity generation that cause
‘‘emissions leakage’’ in uncovered
states. These increases would result in
each state’s emissions being above the
level associated with the prohibition of
all emissions that can be eliminated at
the $500/ton threshold. EPA thus
determined that it is necessary to
establish emission limits for these states
at the $500/ton level. These limits,
although equal to the state’s 2012
projected base case emissions, are
necessary to prohibit all emissions that
can be controlled at the $500/ton cost
threshold. In other words, the
significant contribution to
nonattainment and interference with
maintenance addressed by the ozone
FIPs for these states is the difference
between these states’ projected
emissions if they were not covered
under the Transport Rule (but other
states were), and their emissions after
all emissions that can be eliminated at
$500/ton are prohibited.
In addition, EPA notes that four of
these five states (Arkansas, Indiana,
Louisiana, and Mississippi) are linked
to receptors in either the Houston or
Baton Rouge areas, which are projected
to continue facing nonattainment or
maintenance concerns with the 1997
ozone NAAQS, respectively. To allow
these states to increase emissions above
base case projections would erode the
measurable progress toward eliminating
significant contribution to
nonattainment and interference with
maintenance secured by achieving
ozone-season NOX reductions in the
other states linked to these receptors.
Furthermore, as discussed in section III,
EPA may require additional reductions
in these states to fully address
significant contribution to
nonattainment and interference with
maintenance with respect to the 1997
ozone NAAQS in a future rulemaking to
be proposed after finalizing
reconsideration of the 2008 ozone
NAAQS.
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48263
b. Relationship of Group 1 and Group 2
States for SO2 Control
In the Proposal, EPA chose not to
allow sources in Group 1 states to use
Group 2 SO2 allowances for compliance,
and likewise not to allow sources in
Group 2 states to use Group 1 SO2
allowances for compliance at any time.
The preamble clearly states, ‘‘With
regard to interstate trading, the two SO2
stringency tiers would lead to two
exclusive SO2 trading groups. That is,
states in SO2 Group 1 could not trade
with states in SO2 Group 2’’ (75 FR
45216). No such distinction or
limitation exists for NOX allowance
trading.
EPA received significant public
comment both in support and
opposition to the two distinct SO2
trading programs. Those in opposition
noted that the variability limits imposed
at the state level made the compliance
restrictions between the two groups
unnecessary. Commenters also noted
that it may unfairly penalize sources
that are part of the same airshed, but are
on opposite sides of a state boundary.
Those in favor of the separate SO2
compliance programs noted that it
would reduce the probability of a state
exceeding its variability limit. Allowing
the use of Group 1 or Group 2
allowances for compliance between the
two SO2 programs would potentially
encourage Group 1 states to purchase
allowances instead of making
reductions necessary to eliminate
significant contribution. Group 1 states
are states that need continued
reductions (beyond the $500/ton
threshold) to eliminate their significant
contribution to nonattainment and
interference with maintenance. Group 2
states have already eliminated their
significant contribution to
nonattainment and interference with
maintenance at the $500/threshold. So
to allow Group 1 or Group 2 allowances
to be used interchangeably for
compliance between the two SO2 groups
would be to allow the shifting of
reductions from areas where they are
needed to eliminate significant
contribution to nonattainment and
interference with maintenance to areas
where they are not needed to eliminate
the prohibited emissions. EPA also
agrees that allowing for trading between
the two groups in the remedy finalized
in this action would increase risk of a
state exceeding its variability limit. For
these reasons, EPA is finalizing this
rulemaking with the same prohibition
on SO2 trading between Group 1 and
Group 2 states that was defined in the
proposal. Further, EPA clarifies that
while trading of allowances (i.e.,
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buying, selling, and banking) is allowed
without restriction, it is specifically the
surrender of SO2 allowances for
compliance that is limited. As
mentioned earlier, a source in a Group
1 state can only use SO2 allowances
allocated to Group 1 states for
compliance with the SO2 trading
program. Likewise, a source in a Group
2 state can only use SO2 allowances
allocated to Group 2 states for
compliance with the SO2 trading
program.
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c. Ozone-Season Budgets
EPA established the ozone-season
NOX budgets in a similar manner to the
annual NOX and SO2 budgets by using
the state level emissions from the cost
threshold that reflected the removal of
significant contribution to
nonattainment and interference with
maintenance. Ozone-season budgets
were based on the state level emissions
from fossil-fuel-fired units greater than
25 MW observed at this cost threshold.
As described in section VI.B, all cost
thresholds examined reflected the final
Transport Rule geography and the
marginal costs were applied
accordingly. Therefore, for an ozoneonly state like Florida, the state level
emissions would only reflect an ozoneseason cost threshold of $500/ton in the
final cost curves for 2012 and 2014. For
a state subject to both annual and ozoneseason programs, the marginal cost
curves would reflect a $500/ton NOX
cost year round, a $500/ton SO2 cost in
2012 and the $2,300/ton SO2 cost
starting in 2014 if a Group 1 state.
(1) Length of Ozone Season
(a) Proposed Rule. For purposes of
determining ozone-season budgets in
the proposed rule, EPA defined the
ozone season based on a 5 month period
(May 1 through September 30). This 5
month ozone season was consistent
with the approach taken by the OTAG,
the NOX SIP Call, and CAIR. EPA
requested comment on whether EPA
should base final rule budgets on a
longer season, such as March through
October.
(b) Public Comments. Several
commenters supported continuing with
the May through September time period.
One commenter supported continuing
with this time period, but argued that
EPA should consider lengthening the
ozone season for future efforts. One
commenter questioned the concept of
ozone season budgets and
recommended EPA focus on sources
with greater emissions on high ozone
days.
(c) Final rule. For the final rule, EPA
has retained the approach in the
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proposed rule, as commenters broadly
supported the proposal’s ozone-season
duration and ozone-season NOX
limitations. Notably, many Transport
Rule states covered for PM2.5 reductions
will have sources with annual NOX
controls that are likely to keep operating
year round to address PM2.5 and ozone.
EPA believes that experience from
ozone-season NOX trading has
consistently shown that the emission
measures taken to comply with ozoneseason budgets provide emission
reductions throughout the ozone-season,
including the highest ozone days. (See
NOX Budget Trading Program and CAIR
Program progress reports in the docket
to this rulemaking or at https://
www.epa.gov/airmarkets/progress/
nbp08.html and https://www.epa.gov/
airmarkets/progress/CAIR_09/
CAIR09.html.) However, EPA believes
that there is merit in future Agency
actions addressing ozone transport in
considering strategies to target high
ozone days more specifically.
d. Summary of Cost Thresholds and
Final Budgets for PM2.5 and Ozone
Summary of methodology. In
summary, EPA determined that SO2
emissions that could be reduced for
$2,300/ton in 2014 should be
considered a state’s significant
contribution to nonattainment and
interference with maintenance, unless
EPA determined that a lesser reduction
would fully resolve the nonattainment
and/or maintenance problem for all the
downwind receptors to which a
particular state might be linked. For
these Group 2 states EPA is determining
that a lesser reduction of SO2, based on
the amount of SO2 reductions that can
be reasonably achieved by 2012 is
appropriate. This level is defined by the
reductions observed in the $500/ton
cost threshold. EPA also determined
that all states linked to downwind PM2.5
nonattainment and maintenance
problems should be required to achieve
those emission reductions that can be
reasonably achieved by 2012. Finally,
EPA determined that all states linked to
downwind PM2.5 nonattainment and
maintenance problems should, by 2012,
remove all NOX emissions that can be
reduced for $500/ton and run all
existing controls in 2012.
For ozone-season NOX, EPA
determined that all states linked to
downwind ozone and nonattainment
and maintenance problems should be
required to achieve those ozone-season
emission reductions associated with a
cost threshold of $500 per ton.
Additionally, EPA examined final 2012
and 2014 budgets based on state level
emissions at $500 cost threshold.
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The budget formation methodology
finalized in this action responds to
concerns about state budgets expressed
by commenters on the Transport Rule
proposal. EPA requested comment on
the four step approach used to
determine significant contribution and
determine budgets in the proposal.
Some commenters noted that the state
level emissions from the cost thresholds
used to determine significant
contribution to nonattainment and
interference with maintenance did not
match the state level emissions allowed
by the final budgets. The concern was
that the state level emissions that
reflected the elimination of significant
contribution in the AQAT analysis, in
particular for NOX, were less than the
emissions allowed by the final budgets.
The result would be an implementation
that did not quite fully eliminate the
significant contribution to
nonattainment and interference with
maintenance defined in the rule. The
proposed budgets not matching the
levels reflected in the proposed costing
runs were an artifact of the budget
formation process that relied on a
combination of historic and projected
data. While EPA noted this process
resulted in state budgets that ‘‘reflected’’
EGU emissions at $500/ton, it was not
always consistent with the EGU
emissions at $500/ton in the costing
runs as the commenters noted. By using
the cost curves to determine both
significant contribution to
nonattainment and interference with
maintenance—and state budgets—in the
final rule, EPA addresses the
commenter’s concerns about any
inconsistency between the two in the
proposal.
Some commenters expressed concern
that the Transport Rule would result in
state budgets that were in some cases
higher than those established in CAIR.
Commenters suggested that this would
be inconsistent with requirements or the
spirit of certain CAA provisions aimed
at preventing backsliding, i.e., sections
110(l), 172(e), and 193. However, the DC
Court of Appeals rejected the state
budgets in CAIR as arbitrary and
capricious and not consistent with CAA
section 110(a)(2)(D)(i)(I) (North
Carolina, 531 F.3d 918 and 921) and
remanded CAIR to EPA to promulgate a
new rule replacing CAIR and consistent
with the Court’s decision (North
Carolina, 550 F.3d 1178). As discussed
elsewhere in this section, on remand
EPA developed new, final state budgets
that address the Court’s concerns and
meet section 110(a)(2)(D)(i)(I)
requirements.
Although some state budgets under
the final rule are higher than those
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under CAIR, this does not violate either
the letter or the spirit of CAA provisions
aimed at backsliding. In particular, CAA
section 110(l) provides that the
Administrator may not approve a plan
revision that would ‘‘interfere with any
* * * applicable requirement’’ of the
CAA. 42 U.S.C. 7410(l). Because the
Court reversed and remanded CAIR
with instructions to ‘‘remedy’’ the rule’s
‘‘fundamental flaws’’ (including
specifically the state budgets found to
be unlawful (North Carolina, 550 F.3d
1178), it is difficult to see how new state
budgets replacing unlawful budgets and
meeting section 110(a)(2)(D)(i)(I)
requirements could be viewed as
interfering with requirements of the
CAA. Indeed, the commenters’ approach
would severely limit EPA’s ability to
meet the Court’s mandate to develop a
new rule consistent with section
110(a)(2)(D)(i)(I). See North Carolina,
531 F.3d 921 (explaining that EPA may
not require ‘‘some states to exceed the
mark’’ of eliminating their significant
contribution). Further, the other CAA
sections cited by the commenters
(section 172(e), addressing
circumstances where the Administrator
relaxes a NAAQS, and section 193,
addressing the treatment of
requirements promulgated before the
November 15, 1990, enactment date for
the 1990 Amendments to the Clean Air
Act) are not applicable here.
Additionally, while the CAIR budgets
may have been tighter than Transport
Rule state budgets for a couple of states,
the sum of state budgets that were
subject to both CAIR and the Transport
Rule is lower under the Transport Rule
for the annual programs. Moreover, the
carryover of the large Title IV allowance
bank in CAIR allowed for a great deal
more emissions within any given state
than is permitted under the Transport
Rule.
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E. Approach to Power Sector Emission
Variability
1. Introduction to Power Sector
Variability
Variability is an inherent aspect of the
production and delivery of electricity. It
follows that variations in state
emissions are not only a result of
variations in the level of emission
control, but also are caused by the
inherent variability in power generation.
The state budgets do not account for this
latter source of variability at the state
level. Emission variability is built into
the design of power systems, which use
a wide mix of power generation sources
with varying use and emission patterns
to ensure reliability in electric power
generation. Variations in weather,
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demand due to changes in the level of
economic activity, the portion of electric
generation that is fossil-fuel-fired, the
length and number of outages at power
generation units, and other factors, can
lead to significant variations in the load
levels of different power generation
sources. Variations in the load levels of
sources in any given state cause
variations in the level of emissions in
that state. Thus, EPA believes it is
appropriate, in this rule, to take into
account the variations that are caused
by inherent variability in power
generation. More specifically, variations
in these external variables can cause
significant fluctuations in state
emissions, even when action has been
taken to prohibit all emissions within a
state that significantly contribute to
nonattainment or interfere with
maintenance in another state. For this
reason, EPA considers variability when
determining the state specific
requirements in this rule. EPA does so
by developing variability limits and
assurance levels for each state, as
described in this section, that are
consistent with the statutory mandate of
CAA section 110(a)(2)(D)(i)(I).
Loads on a power system, and thus on
power generation sources in a given
state that are on the power system, vary
over every time interval, changing not
only in the short term and seasonally,
but also annually. As noted above, load
patterns and levels are determined by a
multiplicity of factors, including
weather, economic activity, the portion
of electric generation that is fossil-fuelfired, and the length and number of
outages at power generation units,
which vary over time. In particular,
weather obviously varies not just from
season-to-season but also from year-toyear, and even small changes in annual
weather patterns can affect how the
power system and power generation
sources on the power system operate
during a year. For example, load, and
the resulting use of generation sources
on an interconnected grid to meet load,
depend not only on how hot a summer
day is, but also on where a heat wave
occurs and how long it lasts. Similarly,
a relatively cold winter that drives up
winter load may also change what
generation sources are used to address
the increased demand for heat. Thus,
the pattern of generation may shift
geographically as a weather pattern
moves across the country. Because
weather and other factors affecting
loads, and the patterns of generation
used to meet loads, vary over time and
from state to state, the resulting level of
emissions also varies over time and
from state to state.
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This variability in emissions is not a
result of variation in emission rates,
emission controls, or emission control
strategies, but instead is a result of the
inherent variability in power generation.
Patterns of generation change to ensure
demand for electricity is met and to
ensure continued reliability of the
power system. This results in temporal
and geographic fluctuations in
emissions. In the final Transport Rule,
like the proposed rule, EPA explicitly
takes account of these changing patterns
of generation and the resultant
variability in power sector emissions.
As discussed previously, EPA
identified a specific amount of
emissions that must be prohibited by
each state to meet the requirements of
CAA section 110(a)(2)(D)(i)(I). EPA also
developed state baseline emissions for
power generation sources based on
projections of state emissions in an
average year before the elimination of
prohibited emissions, and state budgets
for power generation sources based on
projections of state emissions in an
average year after the elimination of
such emissions. However, because of
the inherent variability in state-level
baseline emissions—resulting from the
inherent variability in loads and power
system and power generation source
operations—state-level emissions will
fluctuate from year-to-year even after all
significant contribution to
nonattainment and interference with
maintenance that EPA identified in this
final rule are eliminated. In an above
average year, emissions may exceed the
state budgets which are based on an
analysis of projected emissions in an
average year. EPA believes that, because
baseline emissions are variable for
reasons unrelated to the degree of
emission control in a state and
emissions after the elimination of all
significant contribution to
nonattainment and interference with
maintenance are therefore also variable,
it is appropriate to take this variability
into account in developing the remedy
for meeting the requirements of CAA
section 110(a)(2)(D)(i)(I). The variability
limits and assurance levels in the final
rule account for this inherent
variability, while ensuring that
emissions within each state that
significantly contribute to
nonattainment or interfere with
maintenance in another state are
prohibited. EPA believes this approach
is both reasonable in that it reflects the
operation of the power system
generation in order to maintain electric
reliability and consistent with the
statutory mandate of CAA section
110(a)(2)(D)(i)(I). For these reasons, EPA
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is finalizing variability limits for each
state budget to identify the range of
emissions that EPA believes is likely to
occur in each state following the
elimination of all the state’s significant
contribution to nonattainment and
interference with maintenance.
As discussed above, the air qualityassured trading remedy’s state-specific
budgets represent each state’s emissions
in an average year after elimination of
significant contribution to
nonattainment and interference with
maintenance. Because actual base case
emissions are likely to vary from
projected base case emissions, this
remedy incorporates provisions that
account for such variability. While the
primary purpose of this remedy is to
eliminate significant contribution and
interference with maintenance, EPA
believes variability limits also satisfy
several other objectives. The remedy
provides the flexibility to deal with realworld variability in the operation of the
power system through air qualityassured trading and reduces costs of
compliance with emission reduction
requirements, while still providing
assurance for downwind states that
significant contribution to
nonattainment and interference with
maintenance by upwind states will be
eliminated. EPA believes the limited
fluctuation in state level emissions that
this approach permits is consistent with
the statutory mandate of section
110(a)(2)(D)(i)(I) because some
geographic and temporal shifting of
emissions necessarily results from the
inherent variability in power generation
and is caused by factors unrelated to the
degree of emission control, such as
weather, economic activity, and unit
availability. Far from excusing any state
from addressing emissions within the
state that significantly contribute to
nonattainment or interfere with
maintenance in other states, these
variability limits ensure that the system
can accommodate the inherent
variability in the power sector while
ensuring that each state eliminates the
amount of emissions within the state, in
a given year, that must be eliminated to
meet the statutory mandate of section
110(a)(2)(D)(i)(I).
Moreover, the structure of the
program, which achieves the required
emission reductions through limits on
the total number of allowances
allocated, assurance provisions, and
penalty mechanisms, ensures that the
variability limits only allow the amount
of temporal and geographic shifting of
emissions that is likely to result from
the inherent variability in power
generation, and not from decisions to
avoid or delay the installation of
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necessary controls. Under the remedy,
an individual state can have emissions
up to its budget plus the variability
limit. However, the requirement that all
sources hold allowances covering
emissions, and the fact that those
allowances are allocated based on statespecific budgets without variability,
ensure that the total emissions from the
states do not exceed the sum of the state
budgets. The remedy, therefore, ensures
both that total emissions do not exceed
the total of the state budgets and that the
required emission reductions occur in
each state.
This section describes how EPA
calculated variability limits for each
state to achieve this goal.
2. Transport Rule Variability Limits
EPA performed analyses using
historical data to demonstrate that there
is year-to-year variability in base case
emissions (even when emission rates for
all units are held constant) and to
quantify the magnitude of this
variability.
The focus of the analysis is on
quantifying the magnitude of the
inherent year-to-year variability in statelevel EGU emissions independent of
measures taken to control those
emissions (and thus due only to changes
in electricity generation within each
state). EPA used this analysis to set
variability limits as part of the remedy
to ensure that states are eliminating
their significant contribution to
nonattainment and interference with
maintenance to protect air quality.
As discussed in detail below, EPA is
finalizing the Transport Rule with 1year variability limits calculated using a
modified approach from the one
described in the proposal. EPA is not
including the proposal’s 3-year
variability limits in the final Transport
Rule. EPA received comments that the
3-year variability limits increased
program costs and diminished
compliance flexibility without
delivering any additional air quality
benefits. EGU owners and operators
expressed concern that 3-year variability
limits would be impracticable to
implement and that the 1-year
variability limits themselves would be
adequately stringent to ensure
elimination of significant contribution
to nonattainment and interference with
maintenance in each state.
After further consideration, EPA has
concluded that 3-year variability limits
would be unnecessary, would be
difficult to anticipate, and would not
have a measurable impact on air quality
benefits. EPA has determined that
annual limits are sufficient to eliminate
significant contribution to
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nonattainment and interference with
maintenance in all upwind states while
accommodating the historically
observed year-to-year fluctuation in
state-level EGU emissions even at the
same rate of emissions control in a given
state.
In the proposal, EPA used statistical
methods to derive the 3-year variability
limit directly from the 1-year variability
limit, meaning that the two are
statistically equivalent in the long run
under certain statistical assumptions.
Primarily, these assumptions were that
the variation in electric demand around
the budget is random from year-to-year
and that, when the annual emissions are
averaged over a multi-year time period,
the average emissions per year will
equal the state’s budget. The first
assumption was also made in the
assessment of the historical year-to-year
variation in heat input in developing the
1-year limit (see section 2 of the ‘‘Power
Sector Variability Final Rule TSD’’ for
more details). Regarding the second
assumption, since the state-by-state
emission budgets are based on the
availability of emission reductions at an
equal marginal cost level, EPA expects
the sources in each of the upwind states
to make these cost-effective reductions
and to meet the emission budgets each
year, on average.
Since the 3-year variability limit was
based on average year-to-year variability
over a longer time horizon, EPA notes
that a random ordering of those years
could yield 2 above-average years in a
row. If, by chance, a third above-average
year were to follow, the state could face
violation of the 3-year limit, even if over
a time period longer than 3 years, that
state would never have exceeded the
statistically-equivalent 1-year variability
limit and its annual emissions would
have averaged to the level of its budget.
Effectively, this means that imposing a
multi-year variability limit would erode
the 1-year variability limit’s ability to
accommodate historically observed
year-to-year variability in state-level
EGU emissions (due only to generation
changes), and it would do so without
providing any additional air quality
benefits or protection for downwind
areas (since the average emissions over
the long time horizon equal the level of
the budget).
For more details about the
relationship between the 1- and 3-year
limits, see the discussions in section 3
of the ‘‘Power Sector Variability’’ TSD
from the proposed Transport Rule,
which describes the derivation of the 3year limit from the 1-year variability
and section 3 of the ‘‘Power Sector
Variability Final Rule TSD’’, which
describes the results of a numerical
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simulation showing that the 1- and 3year limits are statistically
indistinguishable and, thus, redundant
over the course of the program to
accommodate year-to-year variability.
While EPA expects the yearly
emissions in each state, on average, to
equal the level of the budgets, EPA also
estimated the air quality impacts of 5,
10, 15, and 20 percent emission
variability using the air quality
assessment tool, which is presented in
section 4 of the ‘‘Power Sector
Variability Final Rule TSD.’’ That
analysis shows that year-to-year
fluctuations of up to 20 percent in SO2
emissions from upwind states linked to
a given downwind receptor do not
undermine the ability of the Transport
Rule programs to resolve nonattainment
or maintenance concerns at that
receptor. The analysis presented in the
TSD focuses on SO2 emissions and was
designed to examine the sensitivity of
downwind air quality to upwind EGU
emission levels. The share of total SO2
emitted by EGUs is significantly larger
than the share of total NOX emitted by
EGUs. For example, in the states for
which EPA modeled base case
contributions of these pollutants, EGUs
accounted for 74 percent of total SO2, 14
percent of total annual NOX, and 15
percent of total ozone-season NOX
emissions. Therefore, when varying
EGU emissions only, downwind air
quality would be most sensitive to
upwind variations in SO2, because
relative variations in EGU SO2
emissions have a greater impact on total
SO2 emissions than the same relative
variation in EGU NOX emissions would
have on total NOX emissions affecting
downwind air quality. Because the
Transport Rule only affects upwind
emissions from EGU sources, downwind
air quality would be more sensitive to
variability in upwind state SO2
emissions under this rule than
variability in upwind state NOX
emissions under this rule (given that the
rule affects a smaller scope of total NOX
emissions compared to the scope
affected of total SO2 emissions). Thus,
EPA chose to analyze the ‘‘worst-case’’
potential downwind air quality impacts
from year-to-year variability above
upwind state SO2 budgets, and EPA
therefore believes that its findings from
this analysis are valid for ascertaining
the potential downwind air quality
impacts from variation at those levels in
both SO2 and NOX under the Transport
Rule programs.
Furthermore, because the state
budgets are based directly on IPM
modeling of electric generation when
cost-effective emission reductions have
been achieved, sources within each state
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should have the same incentive to meet
that budget, on average, in any given
year. Additional EPA analysis supports
the claim that states would be no more
likely to exceed 1-year variability limits
without the 3-year limits than with the
3-year limits. See the ‘‘Power Sector
Variability Final Rule TSD’’ for more
details on this statistical analysis.
Finally, because the state budgets (and
thus the total amount of allowances
available) are fixed and every covered
source must hold allowances covering
its emissions, it is not feasible for all, or
even many, states to repeatedly exceed
their budgets.
The approach calculated the standard
deviation in state-level heat input from
units expected to be covered by the final
Transport Rule over an 11-year time
period (2000 through 2010), from which
the 95th percent confidence level was
calculated. EPA divided this value by
the mean to get the percentage variation
in heat input. The two-tailed 95th
percent confidence level is the
equivalent of the 97.5 percent upper
(single-tailed) confidence level. This
approach yielded an average year-toyear heat input variability for each state,
as a proxy for historic year-to-year
variability in state-level EGU emissions
while holding emission rates constant.
The result, expressed as a percentage,
conveys the maximum degree to which
EGU emissions at the state level may be
expected with 95th percent confidence
to vary around a given target (i.e.,
budget) from year-to-year, on average,
based on the statistical analysis of
historic heat input over the 2000
through 2010 time period.
From the state-by-state variability
calculations, EPA identified a single
variability level (percentage) for each of
the annual and ozone-season programs
based on the historic variability
measured at units in covered states on
an annual basis and an ozone-season
basis, respectively. In the proposal, EPA
‘‘identified a single set of variability
levels * * * to apply to all states in
order to make the application of the
variability limits straightforward rather
than developing state-by-state
percentage variability values’’ (75 FR
45293). In the final rule, EPA is taking
the straightforward approach of
identifying a single set of variability
levels to apply to all states because EPA
has determined that it is reasonable to
afford all states under the Transport
Rule programs the extent of measured
historic variability experienced by any
Transport Rule state during 2000
through 2010. In the variability analysis
for the final rule, EPA identified
Tennessee as having the highest
measured historic variability of annual
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heat input of 18 percent, and Virginia as
having the highest measured historic
variability of ozone-season heat input of
21 percent. Because the percentage of
variability in Tennessee on an annual
basis and in Virginia on an ozoneseason basis are reasonably likely to
occur in each of the other states in the
future, EPA believes it is appropriate to
apply an 18 percent annual variability
limit to all states covered by the annual
SO2 and NOX programs and a 21 percent
ozone-season variability limit to all
states covered by the ozone-season NOX
program.54
EPA’s analysis of historic heat input
variability in multiple states over the
2000 to 2010 baseline yields a range of
potential year-to-year variability values
for state-level EGU emissions. As
discussed above, any one state’s
measured variability (in this case, from
2000 to 2010) is due to a multiplicity of
factors. These factors include, but are
not limited to, variation in weather,
variation in demand due to increased or
decreased level of economic activity,
variation in the portion of electric
generation that is fossil-fuel-fired, and
variation in the length and number of
outages at power generation units, and
these individual factors may sometimes
act in concert and may other times be
offsetting.
The mix and levels of factors present
in a state from year-to-year can lead to
variation of state-level emissions above
and below the level for the state under
average conditions. Because the levels
of the various factors are difficult to
predict on a year-to-year basis for an
individual state, the resulting variability
in state-level emissions is difficult to
predict. Moreover, because the electric
generation, transmission, and
distribution system in the eastern half of
the U.S. is highly integrated, year-toyear variation in these factors in one
state can cause year-to-year variability
in state-level emissions both in that
state and in other states on the system.
For example, increased demand due to
extreme weather or increased economic
activity in one state can be met through
increased generation and emissions in a
number of states.
Because these factors can vary year-toyear in every state in ways that are
difficult to predict and can affect other
states, EPA maintains that the maximum
variability measured in one state for a
discrete period (2000–2010) is
54 The six states in the supplemental proposal for
inclusion in the Transport Rule’s ozone-season NOX
program have measured historic ozone-season
variability that would be adequately covered by this
final rule’s ozone-season NOX variability level (21
percent). Please see the ‘‘Power Sector Variability
Final Rule TSD’’ for more details.
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reasonably likely to occur in the future
in any of the states in the region.
Consequently, EPA believes that it is
reasonable to use the maximum historic
percentage variability figure as a proxy
for the percentage variability that any of
the states is likely to experience in the
future. Although EPA is therefore using
a uniform percentage figure for
variability, EPA applies that percentage
figure to each state-specific budget so
that variability in tons of emissions is
determined on a state-specific basis.
That state-specific number is used in
determining whether the assurance
provisions and penalty are triggered in
the specific state. EPA also believes that
it is appropriate to accommodate this
potential future variability at the state
level if and only if it can be
accommodated without undermining
the programs’ beneficial impacts on
downwind air quality that eliminate
significant contribution to
nonattainment or interference with
maintenance of the NAAQS assessed in
this rulemaking (see the ‘‘Power Sector
Variability Final Rule TSD’’ for more
information on this analysis). The
Transport Rule identifies and quantifies,
on a state-by-state basis, the emissions
in each state that significantly
contribute to nonattainment or interfere
with maintenance in another state. This
is done by analyzing specific air
pollution linkages between each
upwind state and each downwind
maintenance or nonattainment receptor.
Nonetheless, it is clear from the air
quality analyses that the air quality
outcome at a given downwind receptor
is a function of the cumulative
emissions from all upwind states and
the receptor’s home state. Once the
Transport Rule emission reduction
requirements are implemented in all
states subject to the programs, EPA’s
analysis shows that the impact on a
downwind receptor of any single
upwind state’s year-to-year fluctuation
of up to 20 percent in SO2 emissions
would be so limited as to not disturb
that receptor’s ability to maintain or
attain the NAAQS analyzed in this
rulemaking. Therefore, to the extent that
such variability has been measured in
historic data in any state subject to the
Transport Rule programs, it is
reasonable to provide for potential
future variability in Transport Rule
states within the scope of what EPA’s
analysis shows to preserve downwind
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air quality gains achieved by the
Transport Rule programs.
The approach to establishing
variability limits in the final rule
modifies the approach from the
proposed rule in two ways. First, EPA
is applying only a percentage variability
limit to each budget in the final rule,
whereas the proposed rule applied the
greater of a percentage or an absolute
tonnage variability limit to each budget.
EPA explained in the proposal that it
was necessary to impose both a
percentage and a tonnage limit due to
the inclusion of ‘‘states with small
numbers of units where expected
variability would be more pronounced
in percentage terms’’ (75 FR 45293).
However, the states with the smallest
numbers of units included at proposal
(such as Connecticut and the District of
Columbia) are not covered by any of the
final Transport Rule’s programs. In the
final rule’s variability analysis,
Tennessee has the highest measured
annual variability percentage and
Virginia has the highest measured
ozone-season variability percentage.
Both of these states have a sufficient
number of units for the percentage
variability findings to be representative
of variability in all of the Transport Rule
states; therefore, it is not necessary to
impose a tonnage limitation in the final
rule.
Second, EPA has expanded the
historic baseline of the variability
analysis to consider heat input data
from 2000 through 2010, as compared to
2002 through 2008 at proposal, and EPA
has also expanded the dataset to include
all units expected to be covered by the
final Transport Rule’s programs. EPA
received a number of comments that the
proposal’s variability limits were too
stringent in part because they relied on
too short a historical baseline that failed
to capture the full extent of long-run
year-to-year variability. EPA agrees with
these comments and believes that the
historic baseline modification described
above supports variability limits in the
final rule that are a better approximation
of future potential year-to-year
variability in state-level EGU emissions
around the budgets as a function of
inherent variability in baseline statelevel EGU operations. EPA believes the
2000 through 2010 historic baseline
supports a more accurate approximation
of year-to-year variability in state-level
EGU operations than previously
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measured on a 2002 through 2008
baseline.
Some commenters expressed the view
that allowing variability limits in
addition to state budgets undermines
the requirements of CAA section
110(a)(2)(D)(i)(I) to eliminate significant
contribution to nonattainment and
interference with maintenance of the
NAAQS in downwind states. EPA
disagrees with these comments. As
explained above, EPA finds that year-toyear variability is an inherent
characteristic of power sector emissions
whether or not such emissions are
controlled by state budgets; the future
year-to-year variability is a component
of the sector’s emissions baseline before
emission reductions are required. As
done for proposal, EPA has analyzed the
impact of allowing emissions from
upwind states in a given year to rise
above the budgets but within the
variability limits allowed in the final
rule. This analysis shows that emission
fluctuations around the budgets but
within the variability limits will not
undermine the downwind air quality
gains achieved by the implementation of
the Transport Rule budgets, and
therefore the variability limits cannot be
said to undermine the elimination of
significant contribution to
nonattainment or interference with
maintenance achieved under the
Transport Rule programs. Based on
historical data and projected air quality
impacts, the Agency believes that states
will have sufficient flexibility and room
to operate within the final rule’s
variability limits while addressing all
emissions identified as significantly
contributing to nonattainment or
interfering with maintenance in other
states.
F. Variability Limits and State Emission
Budgets: State Assurance Levels
As explained above, EPA applied the
variability levels on a state-by-state
basis to calculate specific emission
budgets with variability limits. The state
budget plus the variability limit is also
called the ‘‘state assurance level.’’ Table
VI.F–1 shows final state budgets,
variability limits, and assurance levels
by state for SO2 emissions. Table VI.F–
2 shows final state budgets, variability
limits, and assurance levels by state for
annual NOX emissions. Table VI.F–3
shows final state budgets, variability
limits, and assurance levels by state for
ozone-season NOX emissions.
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TABLE VI.F–1—STATE BUDGETS, VARIABILITY LIMITS, AND ASSURANCE LEVELS FOR SO2 EMISSIONS
Emission budget
(tons)
2012–2013
Alabama ...................................................
Georgia ....................................................
Illinois .......................................................
Indiana .....................................................
Iowa ..........................................................
Kansas .....................................................
Kentucky ..................................................
Maryland ..................................................
Michigan ...................................................
Minnesota .................................................
Missouri ....................................................
Nebraska ..................................................
New Jersey ..............................................
New York .................................................
North Carolina ..........................................
Ohio ..........................................................
Pennsylvania ............................................
South Carolina .........................................
Tennessee ...............................................
Texas .......................................................
Virginia .....................................................
West Virginia ............................................
Wisconsin .................................................
216,033
158,527
234,889
285,424
107,085
41,528
232,662
30,120
229,303
41,981
207,466
65,052
5,574
27,325
136,881
310,230
278,651
88,620
148,150
243,954
70,820
146,174
79,480
Emission variability
limit (tons)
2014 and
beyond
2012–2013
213,258
95,231
124,123
161,111
75,184
41,528
106,284
28,203
143,995
41,981
165,941
65,052
5,574
18,585
57,620
137,077
112,021
88,620
58,833
243,954
35,057
75,668
40,126
38,886
28,535
42,280
51,376
19,275
7,475
41,879
5,422
41,275
7,557
37,344
11,709
1,003
4,919
24,639
55,841
50,157
15,952
26,667
43,912
12,748
26,311
14,306
State emissions
assurance level (tons)
2014 and
beyond
38,386
17,142
22,342
29,000
13,533
7,475
19,131
5,077
25,919
7,557
29,869
11,709
1,003
3,345
10,372
24,674
20,164
15,952
10,590
43,912
6,310
13,620
7,223
2012–2013
2014 and
beyond
254,919
187,062
277,169
336,800
126,360
49,003
274,541
35,542
270,578
49,538
244,810
76,761
6,577
32,244
161,520
366,071
328,808
104,572
174,817
287,866
83,568
172,485
93,786
251,644
112,373
146,465
190,111
88,717
49,003
125,415
33,280
169,914
49,538
195,810
76,761
6,577
21,930
67,992
161,751
132,185
104,572
69,423
287,866
41,367
89,288
47,349
Note: Budgets, limits, and assurance levels apply to each state’s emissions from covered sources, as defined by this final rule, only.
TABLE VI.F–2—STATE BUDGETS, VARIABILITY LIMITS, AND ASSURANCE LEVELS FOR ANNUAL NOX EMISSIONS
Emission budget
(tons)
2012–2013
Alabama ...................................................
Georgia ....................................................
Illinois .......................................................
Indiana .....................................................
Iowa ..........................................................
Kansas .....................................................
Kentucky ..................................................
Maryland ..................................................
Michigan ...................................................
Minnesota .................................................
Missouri ....................................................
Nebraska ..................................................
New Jersey ..............................................
New York .................................................
North Carolina ..........................................
Ohio ..........................................................
Pennsylvania ............................................
South Carolina .........................................
Tennessee ...............................................
Texas .......................................................
Virginia .....................................................
West Virginia ............................................
Wisconsin .................................................
72,691
62,010
47,872
109,726
38,335
30,714
85,086
16,633
60,193
29,572
52,374
26,440
7,266
17,543
50,587
92,703
119,986
32,498
35,703
133,595
33,242
59,472
31,628
Emission variability
limit (tons)
2014 and
beyond
2012–2013
71,962
40,540
47,872
108,424
37,498
25,560
77,238
16,574
57,812
29,572
48,717
26,440
7,266
17,543
41,553
87,493
119,194
32,498
19,337
133,595
33,242
54,582
30,398
13,084
11,162
8,617
19,751
6,900
5,529
15,315
2,994
10,835
5,323
9,427
4,759
1,308
3,158
9,106
16,687
21,597
5,850
6,427
24,047
5,984
10,705
5,693
State emissions
assurance level (tons)
2014 and
beyond
12,953
7,297
8,617
19,516
6,750
4,601
13,903
2,983
10,406
5,323
8,769
4,759
1,308
3,158
7,480
15,749
21,455
5,850
3,481
24,047
5,984
9,825
5,472
2012–2013
2014 and
beyond
85,775
73,172
56,489
129,477
45,235
36,243
100,401
19,627
71,028
34,895
61,801
31,199
8,574
20,701
59,693
109,390
141,583
38,348
42,130
157,642
39,226
70,177
37,321
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Note: Budgets, limits, and assurance levels apply to each state’s emissions from covered sources, as defined by this final rule, only.
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84,915
47,837
56,489
127,940
44,248
30,161
91,141
19,557
68,218
34,895
57,486
31,199
8,574
20,701
49,033
103,242
140,649
38,348
22,818
1 57,642
39,226
64,407
35,870
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TABLE VI.F–3—STATE BUDGETS, VARIABILITY LIMITS, AND ASSURANCE LEVELS FOR OZONE-SEASON NOX EMISSIONS
Emission budget
(tons)
2012–2013
Alabama ...................................................
Arkansas ..................................................
Florida ......................................................
Georgia ....................................................
Illinois .......................................................
Indiana .....................................................
Kentucky ..................................................
Louisiana ..................................................
Maryland ..................................................
Mississippi ................................................
New Jersey ..............................................
New York .................................................
North Carolina ..........................................
Ohio ..........................................................
Pennsylvania ............................................
South Carolina .........................................
Tennessee ...............................................
Texas .......................................................
Virginia .....................................................
West Virginia ............................................
31,746
15,037
27,825
27,944
21,208
46,876
36,167
13,432
7,179
10,160
3,382
8,331
22,168
40,063
52,201
13,909
14,908
63,043
14,452
25,283
Emission variability
limit (tons)
2014 and
beyond
2012–2013
31,499
15,037
27,825
18,279
21,208
46,175
32,674
13,432
7,179
10,160
3,382
8,331
18,455
37,792
51,912
13,909
8,016
63,043
14,452
23,291
6,667
3,158
5,843
5,868
4,454
9,844
7,595
2,821
1,508
2,134
710
1,750
4,655
8,413
10,962
2,921
3,131
13,239
3,035
5,309
State emissions
assurance level (tons)
2014 and
beyond
6,615
3,158
5,843
3,839
4,454
9,697
6,862
2,821
1,508
2,134
710
1,750
3,876
7,936
10,902
2,921
1,683
13,239
3,035
4,891
2012–2013
2014 and
beyond
38,413
18,195
33,668
33,812
25,662
56,720
43,762
16,253
8,687
12,294
4,092
10,081
26,823
48,476
63,163
16,830
18,039
76,282
17,487
30,592
38,114
18,195
33,668
22,118
25,662
55,872
39,536
16,253
8,687
12,294
4,092
10,081
22,331
45,728
62,814
16,830
9,699
76,282
17,487
28,182
Note: Budgets, limits, and assurance levels apply to each state’s emissions from covered sources, as defined by this final rule, only.
See section VII.E for the discussion of
how variability limits and state
assurance levels are used in the
implementation of assurance provisions
for the air quality-assured trading
programs.
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G. How the State Emission Reduction
Requirements Are Consistent With
Judicial Opinions Interpreting the Clean
Air Act
The methodology described in this
notice quantifies states’ significant
contribution to nonattainment and
interference with maintenance in a
manner that is consistent with the
decisions of the DC Circuit. As
discussed previously, the DC Circuit has
issued two significant decisions
addressing the requirements of
110(a)(2)(D)(i)(I). The first opinion
largely upheld the NOX SIP Call,
Michigan, 213 F.3d 663, and the second
found significant flaws in CAIR, North
Carolina, 531 F.3d. 896. In both cases,
the Court considered aspects of the
methodology used by EPA to identify
emissions that, pursuant to section
110(a)(2)(D)(i)(I), must be eliminated
due to their impact on air quality in
downwind states. EPA believes that the
methodology used in this final rule is
consistent with both opinions and
rectifies the flaws the North Carolina
court identified with the methodology
used in CAIR. The methodology used
for this rule relies on state-specific data
to analyze each individual state’s
significant contribution, uses air quality
considerations in addition to cost
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considerations to identify each state’s
significant contribution, and gives
independent meaning to the
‘‘interference with maintenance’’ prong.
This methodology is then applied in a
reasonable manner consistent with the
relevant judicial opinions.
In North Carolina, the Court held that
EPA’s approach to evaluating significant
contribution was inadequate because, by
evaluating only whether emission
reductions were highly cost effective ‘‘at
the regional level assuming a trading
program’’, it failed to conduct the
required state-specific analysis of
significant contribution. See id. at 907.
EPA, the Court concluded, ‘‘never
measured the ‘significant contribution’
from sources within an individual state
to downwind nonattainment areas.’’ Id.
The Court did not, however, disturb the
air-quality-based methodology used by
EPA to identify the states with
contributions large enough to warrant
further consideration.
For this rule, EPA uses a first step
similar to that used in CAIR to identify
the states with relatively large
contributions. However, in contrast to
CAIR, it then uses a state-specific
analysis. Instead of identifying a single
emission level that could be achieved by
the application of highly cost effective
controls in the region, EPA determines,
on a state-by-state basis, what
reductions could effectively be achieved
by sources in each state. EPA’s new
approach does not, as the CAIR
methodology did, establish a regional
cap on emissions that is then divided
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into state budgets that set the emission
reduction requirements for each state.
Instead, EPA develops, for each covered
state, emission budgets based on the
reductions achievable at a particular
cost per ton in that particular state,
taking into account the need to ensure
reliability of the electric generating
system. The selected cost/ton levels
reflect consideration of both cost factors
and air quality factors including the
estimated impact of upwind states’
emissions on each downwind receptor.
In addition, in developing this
approach, EPA was guided by the
Court’s holdings regarding the use of
cost to identify significant contribution.
Specifically, the Court held in Michigan
that EPA could ‘‘in selecting the
‘significant’ level of ‘contribution’ under
section 110(a)(2)(D)(i)(I), choose a level
corresponding to a certain reduction in
cost.’’ North Carolina, 531 F.3d at 917
(citing Michigan, 213 F.3d at 676–77).
This holding also supported the Court’s
conclusion in Michigan that it was
acceptable for EPA to apply a uniform
cost-criterion across states. See
Michigan, 213 F.3d at 679. In the CAIR
case, the Court rejected EPA’s analysis,
not because it relied on cost
considerations to identify significant
contribution, but because it found that
EPA had failed to draw the significant
contribution line at all. See North
Carolina, 531 F.3d at 918 (‘‘* * * here
EPA did not draw the [significant
contribution] line at all. It simply
verified sources could meet the SO2
caps with controls EPA dubbed ‘highly
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cost-effective.’ ’’). The holdings in
Michigan regarding the use of cost and
a uniform cost-criterion across states
were left undisturbed. See, e.g., North
Carolina, 531 F.3d at 917 (explaining
that in Michigan the Court held that
‘‘EPA may ‘after [a state’s] reduction of
all [it] could * * * cost-effectively
eliminate[],’ consider ‘any remaining
contribution insignificant’’). In fact, the
Court acknowledged that, based on the
Michigan holdings, the measurement of
a state’s significant contribution need
not ‘‘directly correlate with each state’s
individualized air quality impact on
downwind nonattainment relative to
other upwind states.’’ North Carolina,
531 F.3d at 908.
For these reasons, EPA determined
that it was appropriate in this
rulemaking to consider the cost of
controls to determine what portion of a
state’s contribution is its ‘‘significant
contribution.’’ However, EPA also
heeded the North Carolina Court’s
warning that ‘‘EPA can’t just pick a cost
for a region, and deem ‘significant’ any
emissions that sources can eliminate
more cheaply.’’ North Carolina,, 531
F.3d at 918. Thus, in this rulemaking,
EPA departs from the practice used in
the NOX SIP Call and in CAIR of
evaluating, based solely on the cost of
control required in other regulatory
environments, what controls would be
considered ‘‘highly-cost-effective.’’
Instead, as part of its determination of
a reasonable cost per ton for upwind
state control, EPA evaluates the air
quality impact of reductions at various
cost levels and considers the
reasonableness of possible cost
thresholds as part of a multi-factor
analysis.
In addition, the methodology used in
this rulemaking gives independent
meaning to the interfere with
maintenance prong of section
110(a)(2)(D)(i)(I). In North Carolina, the
Court concluded that CAIR improperly
‘‘gave no independent significance to
the ‘interfere with maintenance’ prong
of section 110(a)(2)(D)(i)(I) to separately
identify upwind sources interfering
with downwind maintenance.’’ North
Carolina, 531 F.3d at 910. EPA rectified
this flaw in this rulemaking by
separately identifying downwind
‘‘nonattainment sites’’ and downwind
‘‘maintenance sites.’’ EPA decided to
consider upwind states’ contributions
not only to sites that EPA projected
would be in nonattainment, but also to
sites that, based on the historic
variability of their emissions, EPA
determined may have difficulty
maintaining the relevant standards. The
specific mechanism EPA used to
implement this approach is described in
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detail in section V.C, previously. For
annual PM2.5, this approach identified
16 maintenance sites in addition to the
32 nonattainment sites identified in the
analysis of nonattainment receptors. For
24-hour PM2.5 this approach identified
38 maintenance sites in addition to the
92 nonattainment sites identified in the
analysis of nonattainment receptors. For
ozone it identified 16 maintenance sites
in addition to the 11 ozone
nonattainment sites identified.
EPA applied this methodology using
available information and data to
measure the emissions from states in the
eastern United States that significantly
contribute to nonattainment or interfere
with maintenance in downwind areas
with regard to the 1997 and 2006 PM2.5
NAAQS and the 1997 ozone NAAQS.
Although EPA has not completely
quantified the total significant
contribution of these states with regard
to all existing standards, EPA has
determined, on a state-specific basis,
that the emissions prohibited in the FIPs
are either part of or constitute the state’s
significant contribution to
nonattainment and interference with
maintenance. Thus, elimination of these
emissions will, at a minimum, make
measurable progress towards satisfying
the section 110(a)(2)(D)(i)(I) prohibition
on significant contribution to
nonattainment and interference with
maintenance.
VII. FIP Program Structure To Achieve
Reductions
A. Overview of Air Quality-Assured
Trading Programs
EPA is finalizing an air qualityassured trading remedy that is
substantially similar to the preferred
trading remedy presented in the
proposal. Key differences from the
preferred trading remedy in the
proposal include:
• Recalculated state budgets and
variability limits (i.e., state assurance
levels) based on updated modeling;
• Simplified variability limits for
1-year application only;
• Revised allocation methodology for
existing and new units and revised new
unit set-asides for new units in
Transport Rule states and new units
potentially locating in Indian country;
• Changed start of assurance
provisions to 2012 and increased
assurance provision penalties; and
• Removed opt-in provisions.
In the final rule, as in the proposed
rule, EPA is promulgating FIPS to
require SO2 and NOX reductions from
power plants in jurisdictions 55 that
55 Alabama, Arkansas, Florida, Georgia, Illinois,
Indiana, Iowa, Kansas, Kentucky, Louisiana,
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48271
contribute significantly to
nonattainment in, or interfere with
maintenance by, a downwind area with
respect to the 1997 ozone NAAQS, the
1997 annual PM2.5 NAAQS, and/or the
2006 24-hour PM2.5 NAAQS. These FIPs
establish state-specific emission control
requirements using state budgets
starting in 2012, with a second phase of
SO2 reductions in some states in 2014.
Section IV explains EPA’s authority to
issue FIPs.
The air quality-assured trading
remedy in the final rule allows
interstate trading to account for
variability in the electricity sector, but
also includes assurance provisions to
ensure that the necessary emission
reductions occur within each covered
state. The assurance provisions restrict
EGU emissions within each state to the
state’s budget plus the variability limit
and ensure that every state is making
reductions to eliminate the significant
contribution to nonattainment and
interference with maintenance that EPA
has identified. While EPA proposed to
impose these assurance provisions
starting in 2014, the final rule
implements these provisions starting in
2012 (see section VII.E of this
preamble). Additionally, the final FIPs
include penalty provisions adequate to
ensure that the state budget with the
variability limit will not be exceeded.
In the final rule, as in the preferred
trading remedy discussed in the
proposed rule, state-specific emission
budgets without the variability limits
are used to determine the number of
emission allowances allocated to
sources in each state. An EGU source is
required to hold one SO2 or one NOX
allowance, respectively, for every ton of
SO2 or NOX emitted during the control
period. Banking of allowances for use or
trading in future years is allowed.
The final rule establishes four
interstate trading programs, each
starting in 2012: two for annual SO2,
one for annual NOX, and one for ozoneseason NOX. One SO2 trading program
is for sources in states (referred to as
SO2 Group 1) that need to make larger
reductions to eliminate their significant
contribution, while the second is for
sources in states (referred to as SO2
Group 2) that need to make smaller
reductions. A source in a Group 1 state
can only use SO2 allowances allocated
to Group 1 states for compliance with
Maryland, Michigan, Minnesota, Mississippi,
Nebraska, New Jersey, New York, North Carolina,
Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin. As
discussed in section III, in a separate notice, EPA
is proposing to include Iowa, Kansas, Michigan,
Missouri, Oklahoma, and Wisconsin in the ozoneseason NOX requirements.
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the SO2 trading program. A source in a
Group 2 state can only use SO2
allowances allocated to Group 2 states
for compliance with the SO2 trading
program. For compliance in the annual
NOX and ozone-season NOX trading
programs respectively, sources may use
annual NOX and ozone-season NOX
allowances allocated for any state, even
if that state is in a different group for
SO2 than the source’s state. Four sets of
new emission allowances based on the
new state-specific budgets without
variability are allocated to sources, one
set for each of the four trading programs.
Each state has the option of replacing
these FIPs with state rules. EPA believes
that this remedy meets the concerns
raised by the Court in the 2008 North
Carolina decisions which remanded
CAIR to EPA.
In the proposed rule, EPA took
comment on all aspects of the preferred
trading remedy and on two alternative
regulatory options: (1) intrastate trading;
and (2) direct control. EPA also took
comment on a trading ratios approach.
Comments on the Preferred Trading
Remedy: The great majority of public
comments supported the preferred
trading remedy. Most of these
commenters voiced their support for the
broadest possible trading mechanism
because it allows for the most costeffective implementation of any
emission controls. Commenters noted
that flexibility is always needed in the
early years of new programs. Further,
commenters favoring the preferred
remedy agreed with EPA that, by using
state-specific control budgets and
allowing for interstate trading, the
preferred remedy provided electricity
generators the flexibility to undertake
the most cost-effective reductions while
assuring that the resulting reductions
occur within the individual states.
Some commenters that supported the
preferred remedy felt that, while not
ideal, the interstate trading remedy was
preferable to the alternative options of
intrastate trading or direct control.
Many commenters that supported the
preferred remedy felt that the intrastate
trading remedy and direct control
remedy options offer minimal flexibility
from a compliance perspective. They
stated that this lack of flexibility would
unnecessarily increase the cost of
emission reductions.
Other commenters who generally
support the preferred remedy cited
concerns about the level of complexity
in the assurance provisions. One
commenter surmised that the preferred
option creates significant risk where a
company could unexpectedly find itself
in a noncompliance situation due to the
after-the-fact variability analysis.
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Another said that the rule’s features
needlessly reduce the system’s
efficiency and increase complexity.
These commenters generally preferred
unlimited trading, noting that EPA has
proven success with Title IV, the NOX
SIP Call, and CAIR unlimited interstate
trading programs and that allowing
unrestricted interstate trading would
increase flexibility to meet reduction
goals and minimize increases in power
costs.
EPA is finalizing the preferred trading
remedy for the following reasons. EPA
believes this approach is the most costeffective and practical way to comply
with the Court decision in North
Carolina to ensure that all emissions in
a given state that EPA has identified as
significantly contributing to downwind
nonattainment or interfering with
maintenance are eliminated. The vast
majority of public commenters agree. In
addition, this approach provides the
most flexibility for sources while
meeting the Clean Air Act requirements
and protecting public health. As a
result, potential innovations and
resulting cost savings are more likely to
be found and implemented. Based on
historical experience (see the Transport
Rule proposal, 75 FR 45315), EPA has
shown that the results offered by a
flexible trading approach (e.g., flexible
compliance choices, incentives to
reduce emissions early and in the
highest emitting areas, 100 percent
compliance with requirements) are
substantial. A large number of
commenters have corroborated this
assessment. As summarized in the
proposal, EPA believes that the
preferred trading remedy will allow
source owners to choose among several
compliance options to achieve required
emission reductions in the most costeffective manner, such as installing
controls, changing fuels, reducing
utilization, buying allowances, or any
combination of these actions. Interstate
trading with assurance provisions
provides additional regulatory
flexibility that promotes the power
sector’s ability to operate as an
integrated, interstate system and to
provide electric reliability.
Comments on Intrastate Trading: A
few commenters favored the first
alternative, intrastate trading. One
commenter who favored intrastate
trading stated that many power plants
have avoided investment in pollution
controls by buying allowances from
other plants, affecting local air quality
improvement. EPA notes that this
Transport Rule aims to address
emissions from one state that
significantly contribute to
nonattainment or interfere with
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maintenance of certain NAAQS in other
states. Local air quality issues are
directly addressed by other provisions
in the Clean Air Act.
Several commenters raised concerns
about the intrastate trading approach.
Some stated, as EPA noted in the
proposal, that the intrastate trading
option would be more resource
intensive, more complex, less flexible,
and potentially more susceptible to
market manipulation than the other
options. In addition, some commenters
felt that this alternative would provide
less flexibility to ensure electric
reliability than the preferred approach,
resulting in greater private costs to the
power sector and greater social costs for
consumers.
EPA is not finalizing the intrastate
trading option for the following reasons.
As EPA expressed in the proposal and
as commenters have agreed, the
intrastate trading option would be more
resource intensive (both for EPA and for
sources), more complex, less flexible,
and potentially more susceptible to
market manipulation than the preferred
trading approach that EPA is finalizing.
The intrastate trading option would be
more costly and less transparent due to
the large number of trading programs
that would be operated simultaneously
and the large number of annual auctions
that would be held every year to address
the issues of market power within
states. This option would also result in
a greater burden for participants
operating EGUs in multiple states.
Comments on Direct Control Option:
Several commenters favored the second
alternative, direct control. One
commenter stated that direct control—
allowing no trading—was the option
best aligned with the 2008 Court
decisions. EPA disagrees with this
comment for the reasons given below
and because, as explained in this rule,
EPA believes the air quality-assured
trading remedy finalized today is
consistent with the decisions of the DC
Circuit in North Carolina.
Some commenters, who support
direct control, voiced concerns that the
other emission trading approaches
would disadvantage poor and minority
communities or allow increased
emission impacts in neighborhoods near
power plants. EPA notes that a direct
control approach would not require
controls on all plants in a state, but only
on a sufficient number to address the
transport requirements under section
110(a)(2)(d)(i)(I) that this rule addresses,
and therefore would not necessarily
mandate controls on each neighborhood
power plant.
In addition, EPA has conducted an
analysis of the effects of the Transport
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Rule on environmental justice and other
vulnerable communities. We concluded
that, similar to our experience with the
Acid Rain Program,56 many
environmental justice communities are
expected to see large health benefits,
and none are expected to experience
any disbenefits, from implementing an
air quality-assured trading program. The
results of this analysis are presented in
section XII of this preamble and Chapter
5 of the RIA for this rule. In addition,
the CAA provides flexibility for state
and local authorities to impose stricter
limits on sources to address specific
local air quality concerns. Such limits
are independent of the requirements in
this rule, and compliance with
Transport Rule requirements in no way
excuses a source from complying with
other CAA or state law requirements.
Several commenters raised concerns
with the direct control approach. One
commenter felt that issues with
electricity market reliability could occur
during high electricity demand periods
if sources ceased operations due to
approaching their emission rate
limitations under a direct control
remedy. Another commenter was
concerned that applying emission rates
under a direct control remedy to small
municipal units would cause
disproportionate impacts on power
plants where pollution control is more
expensive. Other commenters cited
concerns that EPA’s proposed withinstate company-wide averaging provision
in the direct control proposed
alternative (designed to allow some
flexibility for sources) would place
companies with fewer units at a
disadvantage compared to companies
with more units. EPA generally agrees
with the commenters concerns and has
decided not to finalize the direct control
remedy for the following reasons. EPA
modeling projects that the direct control
alternative would result in fewer
emission reductions and higher costs
compared to the air quality-assured
trading remedy. EPA analysis indicates
that it is not necessary to implement a
direct control approach in order to
protect vulnerable and sensitive
populations or environmental justice
communities. Also, the direct control
approach would result in fewer
compliance options because a direct
control approach would directly
regulate individual sources by setting
unit-level emission rate limits. This lack
of flexibility could lead to potential
56 See https://www.epa.gov/airmarkets/resource/
docs/ejanalysis.pdf and Ringquist, Evan J. 2011.
‘‘Trading Equity for Efficiency in Environmental
Protection? Environmental Justice Effects from the
SO2 Allowance Trading Program.’’ Social Science
Quarterly 92(2):297–323
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increases in reliability risks in the
electric power system and fewer
opportunities for potential technological
innovations that reduce emissions
further and/or lower costs. For these
reasons, EPA believes that this approach
is inferior to the air quality-assured
trading remedy.
Other Comments: A handful of
commenters mentioned the trading
ratios approach, though none favored it
as a viable alternative. One commenter
said the trading ratios approach was not
consistent with CAA section
110(a)(2)(D) requirements that
reductions in emissions occur in
particular geographic locations. Other
commenters agreed that it was
administratively unworkable and would
be difficult to implement due to the
complexity and variety of
meteorological conditions. EPA
generally concurs with the commenters.
In the proposal, EPA noted that it would
not be possible under this approach, as
contemplated, to include enforceable
legal requirements to ensure that a
specific state’s emissions remain below
a specified level or to ensure that a
specific amount of reductions occur
within a particular state. EPA
specifically requested comment on
whether a ratios trading program could
be designed to provide such legal
assurances. Of the few comments
received, none offered such a solution.
For these reasons, EPA is not finalizing
this approach.
Some commenters offered additional
suggestions, such as: unrestricted
trading; using different authorities in
the CAA to address interstate transport
such as section 110(k)(5) and section
126; and an approach that would
replace the assurance provisions by a
system using both emission allowances
usable (as well as bankable) in any state
and assurance allowances usable (but
not bankable) in only the state for which
they would be issued. While EPA
appreciates the thoughtful and
constructive comments, we did not find
any of these suggestions improved our
ability to address interstate transport
under CAA section 110(a)(2)(D)(i)(I), in
line with the Court decision, in an
administratively practical way.
Several commenters liked the idea of
establishing unit-by-unit short-term and
long-term performance standards/
emission rates but suggested adding an
overlaid cap and trade program. EPA
believes the air quality-assured trading
remedy finalized today is consistent
with the decisions of the Court in North
Carolina and will ensure the reductions
necessary to meet statutory
requirements.
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For the 2012–2013 period, EPA took
comment on whether the assurance
provisions are needed, since the statespecific budgets would be based on
known air pollution controls and the
penalty provisions would be adequate to
ensure that the budget, including a
variability limit, would not be exceeded.
Further, EPA proposed to use two
variability limits: a 1-year limit, based
on the year-to-year variability in
emissions relative to the proposed
budgets; and a 3-year limit based on the
variability in a 3-year average relative to
the proposed budget.
Based on comments on the assurance
provisions (see section VII.E of this
preamble) and variability limits (see
section VI.E.2 of this preamble), EPA is
finalizing the Transport Rule with state
budgets plus variability limits and
assurance provisions starting in 2012 for
all of the trading programs. EPA sees an
immediate need to ensure that
emissions within a state do not exceed
the state budget plus the variability
limitation in order to comply with the
Court’s opinion. Further, commenters
stated that the 3-year variability limit
increased costs and unnecessarily
complicated the trading programs. As
explained in section VI.E.2, EPA is
finalizing the 1-year variability limit
starting in 2012, but not the 3-year limit.
B. Applicability
The applicability provisions in the
final rule are, except as discussed
herein, essentially the same as in the
proposed rules and for each of the
Transport Rule trading programs.
Under the general applicability
provisions of the proposed rule, the
Transport Rule trading programs would
cover fossil-fuel-fired boilers and
combustion turbines serving—on any
day starting November 15, 1990 or
later—an electrical generator with a
nameplate capacity exceeding 25 MWe
and producing power for sale, with the
exception of certain cogeneration units
and solid waste incineration units.
EPA requested comment on whether a
more recent year should be used
instead. The proposed use of the
November 15, 1990 date was consistent
with the use of 1990 as the beginning of
the historical period for which owners
and operators would generally be
required to have information about their
units for purposes of determining
whether the units were covered by the
Transport Rule trading programs.
Because unit information is generally
compiled and retained on a calendar
year basis, EPA believes that, for the
general applicability provisions, it is
preferable to use January 1, rather than
November 15. In determining which
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year should be used as the reference
year in the general applicability
provisions, EPA considers several
factors.
First, in order for owners and
operators, and EPA, to be able to
determine which units are subject to the
Transport Rule trading programs, EPA
believes that the reference year should
not be so far in the past that the unit
information necessary to make
applicability determinations is not
readily available. This particularly
becomes an issue in cases of older units
that have changed ownership over time.
EPA found, in making some
applicability determinations under the
CAIR trading programs, that some older
units with ownership changes had
difficulty obtaining information back as
far as twenty or more years. Using
January 1, 1990 as the reference date in
the general applicability provisions
could effectively require some owners
and operators to retain unit information
going back as far as 20 years. As a point
of contrast, under the title V permitting
rules, owners and operators are
generally required to retain data for 5
years. See 40 CFR 70.6(a)(3)(B).
Second, EPA also believes that the
reference year used in the applicability
provisions should be far enough in the
past that the unit information on which
applicability determinations are based
provides a full picture of the nature of
the unit and its operations over time,
such as the types of fuels combusted at
the unit and whether the unit has
produced electricity for sale.
Third, EPA considers whether
selecting a different reference year for
the applicability provisions than the one
in the proposed rule dramatically
changes what units will be covered by
the Transport Rule trading programs. In
this case, EPA believes, based on
available information about the units
potentially subject to the Transport
Rule, that using a somewhat later year
than the one in the proposed rule will
likely have little effect on what units are
covered. Balancing these factors, EPA
concludes that it is reasonable to use
January 1, 2005, rather than November
15, 1990, in the general applicability
provisions in the final rule.
In the final rule, EPA is taking the
same approach with regard to defining
whether a boiler or combustion turbine
is considered to be ‘‘fossil-fuel-fired’’ as
the one used in the proposal. Under the
proposed rule, a unit was considered to
be ‘‘fossil-fuel-fired’’ if it combusts any
amount of fossil fuel at any time in 1990
or later. For the same reasons that EPA
decided to use January 1, 2005 in the
general applicability provisions, and in
order to have a consistent reference year
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in all applicability-related provisions,
the final rule defines a ‘‘fossil-fuelfired’’ unit as one that combusts any
amount of fossil fuel in 2005 or later.
EPA notes that the final Transport
Rule allows a state to submit a SIP
revision (an abbreviated or full SIP)
under which the state may—in addition
to making certain types of changes
concerning allowance allocations in the
Transport Rule trading programs—
expand the general applicability
provisions of the Transport Rule NOX
Ozone Season Trading Program to cover
fossil-fuel-fired boilers and combustion
turbines serving—at any time starting
January 1, 2005 or later— a generator
with a nameplate capacity as low as 15
MWe producing power for sale. The
exemptions, discussed below, for
cogeneration units and solid waste
incineration units still will continue to
apply.
Cogeneration unit exemption. Under
the final rule (as well as the proposed
rule) certain cogeneration units or solid
waste incinerators are exempt from the
FIP requirements. In particular, the final
rule includes an exemption for a unit
that qualifies as a cogeneration unit
throughout the later of 2005 or the first
12 months during which the unit first
produces electricity and continues to
qualify through each calendar year
ending after the later of 2005 or that 12month period and that meets the
limitation on electricity sales to the grid.
In order to meet the definition of
‘‘cogeneration unit’’ in the final rules, a
unit (i.e., a fossil-fuel-fired boiler or
combustion turbine) must be a toppingcycle or bottoming-cycle that operates as
part of a ‘‘cogeneration system,’’ which
is defined as an integrated group of
equipment at a source (including a
boiler, or combustion turbine, and a
steam turbine generator) designed to
produce useful thermal energy for
industrial, commercial, heating, or
cooling purposes and electricity through
the sequential use of energy. A toppingcycle unit is a unit where the sequential
use of energy results in production of
useful power first and then, through use
of reject heat from such production, in
production of useful thermal energy. A
bottoming-cycle unit is a unit where the
sequential use of energy results in
production of useful thermal energy first
and then, through use of reject heat from
such production, in production of
useful power. In order to qualify as a
cogeneration unit, a unit also must meet
certain efficiency and operating
standards.
In the proposed rule, a unit would
have to qualify as a cogeneration unit
and meet the limitation on electricity
sales starting the later of 1990 or the
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year when the unit begins operating.
EPA requested comment on whether a
more recent year should be used. For
the reasons discussed above concerning
the reference year used in the general
applicability provisions and in order to
have a consistent reference year in all
applicability-related provisions, EPA
concludes that it is reasonable to use
2005, rather than 1990, in the
cogeneration unit exemption provisions
in the final rule. Consequently, the final
rule provides that the requirements to
qualify as a cogeneration unit and to
meet the electricity sales limitation start
no earlier than 2005.
In the final rule, EPA also clarifies
that the electricity sales limitation
under the exemption is applied in the
same way whether a unit serves only
one generator or serves more than one
generator. In both cases, the total
amount of electricity produced annually
by a unit and sold to the grid cannot
exceed the greater of one-third of the
unit’s potential electric output capacity
or 219,000 MWhr. This is consistent
with the approach taken in the Acid
Rain Program (40 CFR 72.7(b)(4)), where
the cogeneration unit exemption
originated. EPA believes that this
clarification is needed to ensure that a
unit serving, for example, two
generators would not have a limit on
sales of electricity to the grid that would
be different (i.e., twice as high) from the
limit for a unit serving only one
generator with the same total nameplate
capacity as the first unit’s two
generators.
EPA also took comment on whether
efficiency standards should be applied
on a system-wide basis to bottomingcycle units (where useful thermal
energy is produced before useful power
is produced), as they are for toppingcycle units (where useful thermal
energy is produced after useful power)
and whether to exclude, from the
requirement to meet the operating and
efficiency standards, calendar years
during which a cogeneration unit does
not operate at all. Several commenters
argued EPA should apply efficiency
standards to both types of units. EPA
agrees that applying efficiency
standards on a system-wide basis to
both bottoming-cycle and topping-cycle
units is reasonable because EPA sees no
technical reason to distinguish between
the two types of units in this instance.
EPA further agrees with commenters
that excluding calendar years in which
the cogeneration unit does not operate
at all, i.e., does not combust any fuel,
from the requirements to meet operating
and efficiency standards is also
reasonable. For such a year, the unit
would not produce any useful thermal
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energy or useful power and therefore
could not meet the minimum output
requirements in the operating and
efficiency standards, but the unit also
would not have any emissions. For
these reasons, the final rule expressly
provides that the operating and
efficiency standards do not have to be
met for a calendar year throughout
which a unit did not operate at all.
Solid waste incineration unit
exemption. The final rule also includes
an exemption for a unit that qualifies as
a solid waste incineration unit during
the later of 2005 or the first 12 months
during which the unit first produces
electricity, that continues to qualify
throughout each calendar year ending
after the later of 2005 or that 12-month
period each year thereafter, and that
meets the limitation on fossil-fuel use.
In contrast, the exemption for solid
waste incineration units in the proposed
rule distinguished between units
commencing operation before January 1,
1985 and those commencing operation
on or after that date. A unit commencing
operation before January 1, 1985 would
be exempt if it qualified as a solid waste
incineration unit starting the later of
1990 or the year when it began
producing electricity and its average
annual fuel consumption of non-fossil
fuels exceeded 80 percent of total heat
input during 1985–1987 and during any
three consecutive calendar years after
1990. A unit commencing operation on
or after January 1, 1985 would be
exempt if it qualified as a solid waste
incineration unit starting the later of
1990 or the year when it began
producing electricity and its average
annual fuel consumption of non-fossil
fuel exceeded 80 percent of total heat
input for the first 3 calendar years of
operation and for any 3 consecutive
calendar years thereafter.
In the proposal, EPA requested
comment on whether it would be
problematic to obtain sufficiently
detailed information about unit
operation potentially as far back as
1985–1987 and 1990, and whether the
fuel consumption standard for each unit
should be limited to more recent years.
For the reasons discussed above
concerning the reference year used in
the general applicability provisions and
in order to have a consistent reference
year for all applicability-related
provisions, EPA concludes that it is
reasonable to use 2005, rather than
1990, in the solid waste incineration
unit exemption in the final rule. In
particular, EPA notes that the proposed
provisions for units commencing
operation before January 1, 1985 and for
units commencing operation on or after
January 1, 1985 could require some
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owners and operators to retain unit
information going back more than 20
years before the promulgation of this
final rule. Further, EPA believes that
removing the distinction between units
commencing operation during these two
periods, and referencing somewhat later
years as the earliest years for which
information on fossil-fuel consumption
is required, will result in the exemption
still being based on sufficient data to
provide a full picture of the nature and
operation of the units involved. EPA
also believes, based on available
information about the units potentially
subject to the Transport Rule, that this
approach will not significantly change
which units qualify for the exemption.
Consequently, the final rule removes the
distinction based on whether a solid
waste incineration unit commences
operation before January 1, 1985 or on
or after January 1, 1985. In order to be
exempt, the unit must qualify as a solid
waste incineration unit during the later
of 2005 or the first 12 months during
which the unit first produces electricity,
must continue to qualify throughout
each calendar year ending after the later
of 2005 or that 12-month period, and
must meet the limitation on fossil-fuel
use on a 3-year average basis during the
first 3 years of operation starting no
earlier than 2005 and every 3 years of
operation thereafter.
Opt-in units. EPA is not finalizing the
opt-in provisions that were discussed in
the Transport Rule proposal. EPA
proposed opt-in provisions to allow
non-covered units to voluntarily opt in
to any of the proposed Transport Rule
trading programs and receive allocations
reflecting 70 percent of the unit’s
emissions before opting in. These
allowances were above the state-specific
budgets developed under the Transport
Rule to eliminate a state’s significant
contribution to nonattainment and
interference with maintenance. In
theory, an opt-in unit that makes
reductions below its baseline and sells
the freed-up allowances is effectively
substituting its new, lower-cost
reductions for higher-cost reductions
otherwise required by a covered EGU,
with the result that the state’s
significant contribution is still
eliminated but at a lower total program
cost.
EPA notes that theoretical benefits
anticipated from allowing opt-ins did
not materialize in prior trading
programs with opt-in provisions. The
Acid Rain Program has about 23 opt in
units; the NOX Budget Trading Program
had five opt-in units; and no units opted
into the CAIR programs. As a group,
these opt-in units neither eased the
achievement of required emission
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reductions in past trading programs, nor
reduced overall program costs.
In the proposal, EPA requested
comment on the opt-in provisions,
specifically regarding: What are the
benefits of and concerns about
including opt-in provisions; how to
ensure units are not credited for
emission reductions the units would
have made anyway; whether the
proposed 30 percent reduction (i.e.,
application of the 70 percent multiplier
to baseline emissions) or some other
percentage reduction, or no reduction,
should be applied to the baseline
emission rate used in determining
allocations; and whether any additional
percentage reduction (such as 45
percent) should be applied to SO2
Group 1 opt-in units in Phase II to
reflect the stricter limits for covered
units.
Some commenters argued that
increasing the Transport Rule budgets
for opt-ins would undermine the goal of
CAA section 110(a)(2)(D)(i)(I) to
eliminate a state’s significant
contribution to nonattainment and
interference with maintenance. One
commenter stated that it does not favor
allowing sources that are not subject to
the emission reduction requirements to
be issued allowances that would
increase the overall state emission
budgets, due to the uncertainty that any
reductions made by such units would be
surplus, verifiable, permanent and
enforceable. This could compromise the
integrity of the EGU emission reduction
requirements of the Transport Rule and
jeopardize assurance that a state’s
significant contribution would be
eliminated, as required by the Court in
North Carolina. Other commenters
claim that, while no cheap tons are
available from non-EGUs and EPA is
right not to require non-EGU reductions,
EPA should nonetheless allow nonEGUs to choose voluntarily to be
covered by opting in.
As mentioned previously, the final
Transport Rule does not include any
opt-in provisions either in the FIPs or in
the provisions allowing modification or
replacement of the FIPs through
submission of trading program
provisions in SIPs. EPA has several
reasons for not adopting provisions to
allow opt-in units. First, as mentioned
above, historically, very few units have
opted in. As of 2010, 28 units out of
more than 4,700 covered units (23 units
out of a total of about 3,600 covered
units in the Acid Rain Program and 5
units out of a total of about 2,600
covered units in the NOX SIP Call) have
opted in to EPA trading programs over
the past 15 years. In the Acid Rain
Program, 3 of the units opted in and
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then, effective for 2005, opted out. Four
of the units opted in, immediately shut
down, and continue to receive
allowance allocations. Four of the units
opted in and continue to operate and
receive allowance allocations. Finally,
12 of the units opted in, after CAIR was
finalized, in order to receive allowances
usable for compliance in the CAIR SO2
trading program. Because CAIR will be
replaced by this Transport Rule, EPA
anticipates that these 12 units will opt
out of the Acid Rain Program. In the
NOX Budget Trading Program, 3 plants
with 5 opt-in units received allocations
between 2003 and 2008.
Moreover, EPA has determined that
the inclusion of opt-in units in the
Transport Rule trading programs would
undermine the rule’s objective of
addressing emissions in each state that
significantly contribute to
nonattainment or interfere with
maintenance in other states. As
explained above, EPA has established
budgets plus variability limits that states
must meet to ensure that the significant
contribution to nonattainment and
interference with maintenance
identified by EPA is addressed. If EPA
were to allow opt-ins, and if any opt-in
unit were to receive an allocation of
allowances for emissions that would be
reduced even if the units did not opt in,
then the inclusion of that opt-in unit in
the program would allow the sources
covered by the Transport Rule to emit
in excess of the budget plus variability
limit with no new, offsetting reduction
in emissions. For example, after a unit
would opt in, process or fuel changes
made for economic reasons (rather than
due to any regulatory requirements), or
installation of new emission controls or
fuel-switching conducted to meet
future, non-Transport Rule regulatory
requirements, could result in emission
reductions that would have occurred
‘‘anyway’’ (i.e., even if the unit had not
opted in), and the opt-in unit would be
allocated allowances for the portion of
its baseline emissions that would be
removed by these ‘‘anyway’’ reductions.
Allocations above the cap to opt-in units
making ‘‘anyway’’ emission reductions
would convert these reductions into
extra allowances (i.e., authorizations to
emit) usable by covered EGUs to meet
their requirements to hold allowances
for emissions. Because the extra EGU
emissions authorized by these extra
allowances would not be offset by any
new emission reductions by the opt-in
units, this could threaten a state’s ability
to eliminate the significant contribution
to nonattainment and interference with
maintenance identified by EPA in the
final rule. Also, opt-in units, which are
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allocated allowances outside the state
budget for covered units, could increase
the possibility that a state’s total
emissions would exceed the state
budget plus variability and thus that the
assurance provisions would be
triggered.
This problem of allocating allowances
for emissions that would have been
reduced anyway is illustrated by the
recent promulgation of the final rule,
National Emission Standards for
Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and
Institutional Boilers and Process Heaters
(76 FR 15608 (March 21, 2011)) (‘‘final
Boiler MACT rule’’), which requires
certain industrial, commercial, and
institutional boilers to meet maximum
achievable control technology (MACT)
standards for emissions of specified
hazardous air pollutants, such as
hydrogen chloride (HCL) and mercury
(Hg). Some of the control technologies
that can be used to meet these standards
will also provide significant reductions
of SO2 emissions. For example, a boiler
may use a wet scrubber or the
combination of a dry sorbent injection
system and a fabric filter (among other
options) to meet the applicable HCL
standard or may use a wet scrubber or
a combination of activated carbon
injection and a fabric filter (among other
options) to meet the applicable Hg
standard. See 76 FR 15614 (describing
testing and compliance requirements
when such controls are used to meet
these standards); and Memo from Brian
Shrager to Amanda Singleton and
Graham Gibson, Revised Methodology
for Estimating Cost and Emissions
Impacts for Industrial, Commercial and
Institutional Boilers and Process Heaters
National Emissions Standards for
Hazardous Air Pollutants—Major
Source (February 11, 2011), Document
ID EPA–HQ–OAR–2009–0491–4036
(section 3.1, describing control options
for HCL and Hg control). In fact, EPA
estimated that the new standards would
result in emission reductions of not only
the hazardous air pollutants directly
subject to the standards, but also in
other air pollutants such as SO2.
Specifically, EPA projected that
compliance with the final Boiler MACT
rule standards will result in about
431,000 tons of annual SO2 reductions
from existing boilers subject to the final
Boiler MACT rule. This will comprise
on average about a 46 percent reduction
in SO2 emissions for this group of
boilers. Coal- and oil-fired boilers—
which are the boilers likely to have the
most uncontrolled SO2 emissions and so
would be the most likely types of units
to consider opting into the Transport
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Rule trading programs if opting-in were
allowed—are projected to reduce about
409,000 tons of annual SO2 as a result
of complying with the final Boiler
MACT rule, or about a 50 percent
reduction in SO2 emissions. See Memo
from Brian Shrager to Amanda
Singleton and Graham Gibson,
Appendix B–1, (where column CE
represents baseline SO2 emissions and
column CH represents SO2 reductions
resulting from the final Boiler MACT
rule compliance). The amount of
offsetting SO2 increases projected to
result from final Boiler MACT rule
compliance, e.g., from additional fuel
being combusted to generate electricity
to operate emission controls, is minor.
See 76 FR 15651 (Table 4) and 15653
(showing projected total SO2 reductions
for all boilers and process heaters of
about 442,000 tons and net SO2
reductions of about 440,000 tons).
Consequently, a boiler subject to the
final Boiler MACT rule may install a
wet acid gas scrubber or a bag house in
order to meet the HCL or Hg standard
applicable to boilers under the final
Boiler MACT rule and thereby achieve
SO2 emission reductions. If that boiler
were to opt in to one of the Transport
Rule SO2 trading programs during the
year before installing these controls to
comply with the final Boiler MACT
rule, then the boiler would be allocated
allowances for the unit’s current tons of
SO2 emissions and would not need to
use these allowances for compliance
under the Transport Rule once the final
Boiler MACT-related controls were
installed. The allowances allocated to
the boiler would be additional
allowances above the Transport Rule
trading budget for the state where the
boiler was located. As a result, the
boiler would have freed-up allowances
above the state trading budget that
represent reductions that the boiler
would have made anyway (i.e., even if
the boiler had not opted in) and that
could be sold to EGUs covered by the
Transport Rule. In effect, the opting-in
of the boiler would result in the
conversion of the boiler’s SO2
reductions from the final Boiler MACT
rule into increased emissions above the
state trading budget from EGUs subject
to the Transport Rule.
Commenters addressed this issue. For
instance, one commenter suggested that
SO2 reductions made by a boiler under
the final Boiler MACT rule should be
eligible for opt-in provision allowances
under the Transport Rule trading
programs. Another commenter stated
that, given the uncertainty that
reductions made by opt-in units would
be surplus, verifiable, permanent, and
enforceable, opt-in provisions could
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compromise the integrity of the EGU
emission reductions.
For the reasons explained above, EPA
agrees with the latter commenter.
Further, EPA notes that none of the
commenters supporting adoption of the
opt-in provisions suggested any revision
to the proposed opt-in provisions that
would address this problem. While the
proposed opt-in provisions would limit
an opt-in unit’s allocation for a control
period by calculating the allocation
using the lesser of the unit’s pre-opt-in
SO2 emission rate or the most stringent
SO2 emission rate applicable in that
control period, this would not address
SO2 rate reductions that are not directly
required by the final Boiler MACT rule
but that are a secondary result of using
and operating certain emission controls
installed to comply with the HCL or Hg
standards under the final Boiler MACT
rule. Because the secondary SO2
reductions will vary depending on the
type of controls installed and on the
extent to which the controls are used,
and a boiler may use a combination of
emission controls and other approaches
to reduce HCL or Hg emissions (such as
fuel switching), EPA believes that it is
highly unlikely that opt-in provisions
could prevent allocation for ‘‘anyway’’
emission reductions resulting from
compliance with the final Boiler MACT
rule. EPA therefore believes that the
final Boiler MACT rule provides a
concrete example of why adoption of
opt-in provisions could undermine the
rule’s objective of addressing emissions
in each state that significantly
contribute to nonattainment or interfere
with maintenance in other states. EPA
notes that the final Boiler MACT rule,
of course, is simply one example of how
allocations for ‘‘anyway’’ reductions
could occur and undermine the
statutory requirements of the Transport
Rule.
C. Compliance Deadlines
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1. Alignment With NAAQS Attainment
Deadlines
The compliance dates in the final
Transport Rule are aligned with the
attainment deadlines for the relevant
NAAQS and consistent with the charges
given to EPA by the Court in North
Carolina. EPA proposed to require, and
the final rule requires, compliance by
2014 with an initial phase of reductions
in 2012.57 Sources are required to
57 For the annual programs, sources are required
to have, by March 1, 2013, sufficient allowances in
their accounts to cover their 2012 emissions. For
the ozone-season program, they must have
allowances in their accounts by December 1, 2012
to cover 2012 ozone-season emissions. The state
budgets which determine the number of allowances
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comply with annual SO2 and NOX
requirements by January 1, 2012 and
January 1, 2014 for the first and second
phases, respectively. Similarly, sources
are required to comply with ozoneseason NOX requirements by May 1,
2012, and by May 1, 2014. In selecting
these dates, EPA was mindful of the
NAAQS attainment deadlines which
require reductions as expeditiously as
practicable and no later than specified
dates (see 42 U.S.C. 7502(a)(2)(A)
(general attainment dates); 42 U.S.C.
7511(a)(1) (attainment dates for ozone
nonattainment areas)), and also mindful
of the court’s instruction to ‘‘decide
what date, whether 2015 or earlier, is as
expeditious as practicable for states to
eliminate their significant contributions
to downwind nonattainment.’’ North
Carolina, 531 F.3d at 930.
1997 PM2.5 NAAQS Attainment
Deadlines. For all areas designated as
nonattainment with respect to the 1997
PM2.5 NAAQS, the deadline for attaining
that standard is as expeditious as
practicable but no later than April 2010
(5 years after designation), with a
possible extension to no later than April
2015 (10 years after designation).58
Many areas have already come into
attainment by the April 2010 deadline
due in part to reductions achieved
under CAIR. The fact that the 2010
deadline will have passed before the
Transport Rule is finalized emphasizes
the importance of obtaining reductions
as expeditiously as practicable. In
addition, reductions achieved in
upwind states by the 2014 emissions
year will help downwind states
demonstrate attainment by the April
2015 deadline.
2006 PM2.5 NAAQS Attainment
Deadlines. For all areas designated as
nonattainment with respect to the 2006
24-hour PM2.5 NAAQS, the attainment
deadline must be as expeditious as
practicable but no later than December
2014. Areas that fail to meet that
deadline can request an extension to as
late as December 2019.
Upwind emission reductions
achieved by the 2014 emissions year
allocated to units in each state become more
stringent for some states in 2014.
58 Section 172(a)(2) of the Clean Air Act provides
that the attainment dates for areas designated
nonattainment with a NAAQS shall be the date by
which attainment can be achieved as expeditiously
as practicable, but no later than 5 years from the
date of designation. This section also allows the
Administrator to extend the attainment date to the
extent she determines appropriate, for a period no
greater than 10 years from the date of designation
as nonattainment, considering the severity of
nonattainment and the availability and feasibility of
pollution control measures. Designations for the
1997 PM2.5 NAAQS became effective on April 5,
2005. Designations for the 2006 24-hour PM2.5
NAAQS became effective on December 14, 2009.
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will help meet the December 2014
attainment deadline. In addition, the
first phase of reductions in 2012 will
help many areas attain in a more
expeditious manner.
Further, a deadline of January 1, 2014
also provides adequate and reasonable
time for sources to plan for compliance
with the Transport Rule and install any
necessary controls. EPA believes that
this deadline is as expeditious as
practicable for the installation of the
controls, if any, needed for compliance
with the 2014 state emission budgets.
(See further discussion in section
V.C.2.)
1997 Ozone NAAQS Attainment
Deadlines. Ozone nonattainment areas
must attain permissible levels of ozone
‘‘as expeditiously as practicable,’’ but no
later than the date assigned by EPA in
the ozone implementation rule. 40 CFR
51.903. The areas designated
nonattainment in 2004 with respect to
the 1997 8-hour ozone NAAQS in the
eastern United States were assigned
maximum attainment dates effectively
corresponding to the end of the 2006,
2009, and 2012 ozone seasons. The
maximum attainment deadlines for the
1997 standard run from the June 15,
2004 effective date of designation for
that standard. The time periods are
based on the time periods provided for
these classifications in section 181 of
the Act, 45 U.S.C. 7511(a). However,
instead of running from the 1990 date of
enactment of the CAA as specified in
section 181, our regulation provides that
they run from the date of designation.
An area’s maximum attainment date is
based on its nonattainment
classification—that is, whether it is
classified as a marginal, moderate,
serious, severe, or extreme ozone
nonattainment area. Marginal areas have
three years from designation to attain
the standard. Moderate, serious, severe,
and extreme areas have 6, 9, 15, and 20
years, respectively. The maximum
attainment deadlines associated with
the 1997 ozone standards are June 15,
2007 for marginal areas, June 15, 2010
for moderate areas, and June 15, 2013
for serious areas. Because the actual
deadline occurs in the middle of an
ozone season, data from that ozone
season is not considered when
determining whether the area has
attained by the deadline. Thus, these
maximum attainment deadline dates
effectively correspond with the end of
the 2006, 2009, and 2012 ozone seasons.
Reductions achieved or air quality
improvements realized after those dates
will not help the areas meet their
maximum attainment deadlines.
Many areas have already attained the
standard due in part to CAIR, federal
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mobile source standards, and other
local, state, and federal measures. Other
areas, however, have been reclassified to
a higher classification either because
they failed to attain by their attainment
date or because the state requested
reclassification to avoid missing an
attainment date. Those that have not yet
attained the standard now have
maximum attainment dates ranging
from June 2011 (these are the moderate
areas that have been granted a 1-year
extension due to clean data for the 2009
ozone season) to June 2024. The areas
classified as ‘‘serious’’ nonattainment
areas have a June 2013 maximum
attainment deadline. Areas that missed
their earlier deadlines and have been
reclassified as ‘‘severe’’ or ‘‘extreme’’
nonattainment areas now have
maximum nonattainment deadlines of
June 2019 and June 2024 respectively.
As explained above, an area with a June
2013 deadline would need to attain
based on ozone data from the 2010–
2012 ozone seasons, an area with a June
2019 deadline would need to attain
based on ozone data from the 2016–
2018 ozone seasons, and an area with a
June 2024 deadline would need to attain
based on ozone data from the 2021–
2023 ozone seasons.
The Transport Rule’s first phase of
reductions in 2012 will help the
remaining areas with June 2013
maximum attainment deadlines attain
the 1997 8-hour ozone NAAQS by their
deadline. If EPA determines that an area
failed to attain by the 2013 deadline, the
area would be reclassified to severe and
would be subject to the more stringent
emission control requirements that
apply to the severe classification. The
reductions will also help areas with
later deadlines attain as expeditiously as
practicable and improve air quality in
those areas.
2012 Interim Compliance Deadline.
EPA is requiring an initial phase of
reductions starting in 2012. These
reductions are necessary to ensure that
significant contribution to
nonattainment and interference with
maintenance are eliminated as
expeditiously as practicable and in time
to help states meet their attainment
deadlines. As the court emphasized in
North Carolina, the significant
contribution to nonattainment and
interference with maintenance from
upwind states must be eliminated as
expeditiously as practicable to help
downwind states to achieve attainment
as expeditiously as practicable as
required by the CAA. Further,
reductions are needed by 2012 to help
states attain before the June 2013
maximum attainment date for ‘‘serious’’
ozone nonattainment areas, to ensure
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states attain as soon after the original
April 2010 attainment deadline for the
1997 PM2.5 NAAQS, and to help states
attain before the December 2014
attainment deadline for the 2006 PM2.5
NAAQS.
In addition, because this final rule
will replace CAIR, EPA could not
assume that after this rule is finalized,
EGUs would continue to emit at the
reduced emission levels achieved by
CAIR. Instead, it is the emission
reduction requirements in the proposed
FIPs that will determine the level of
EGU emissions in the eastern United
States. For this reason also, EPA
concludes that it is appropriate to
require an initial phase of reductions by
2012 to ensure that existing and
planned SO2 and NOX controls operate
as anticipated.
Addressing the Court’s Concern about
Timing. As directed by the Court in
North Carolina, 531 F.3d 896, and as
described previously, EPA established
the compliance deadlines in the
Transport Rule based on the respective
NAAQS attainment requirements and
deadlines applicable to the downwind
nonattainment and maintenance sites.
The 2012 deadline for compliance
with the limits on ozone-season NOX
emissions is necessary to ensure that
states with June 2013 maximum
attainment deadlines get the assistance
needed from upwind states to meet
those deadlines. The 2012 deadline for
compliance with the limits on annual
NOX and annual SO2 emissions is
necessary to ensure attainment as
expeditiously as practicable in areas
which failed to attain by the 2010
attainment deadline for the 1997 PM2.5
NAAQS and had to request an extension
to 2015.
Similarly, the 2014 deadline for
compliance with the limits on annual
NOX and annual SO2 emissions is
necessary to ensure that downwind
states get the benefit of upwind
reductions prior to the December 2014
maximum attainment deadline for the
2006 PM2.5 NAAQS. It is also necessary
to ensure reductions occur in time to
assist with attainment in downwind
areas that received the maximum 5-year
extension of the 5-year attainment
deadline for the 1997 PM2.5 NAAQS
(taking into account the need for
reductions by 2014 to demonstrate
attainment by April 2015).
The 2012 compliance deadline for the
first-phase of annual NOX and annual
SO2 emission reductions will assure the
reductions are achieved as
expeditiously as practicable. A
significant amount of the emissions
identified as significantly contributing
to nonattainment or interfering with
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maintenance in other states can be
eliminated by 2012. EPA believes it is
appropriate to do so in light of the
court’s direction to EPA to ensure states
eliminate such emissions as
expeditiously as practicable. North
Carolina 531, F.3d at 930. Given the
time needed to design and construct
scrubbers at a large number of facilities,
EPA believes the 2014 compliance date
is as expeditious as practicable for the
full quantity of SO2 reductions
necessary to fully address the significant
contribution to nonattainment and
interference with maintenance.
Requiring reductions in transported
pollution as expeditiously as
practicable, as well as within maximum
deadlines, helps to promote attainment
as expeditiously as practicable. This is
consistent with statutory provisions that
require states to adopt SIPs that provide
for attainment as expeditiously as
practicable and within the applicable
maximum deadlines.
b. Public Comments and EPA Responses
EPA received numerous comments on
the proposed compliance dates. A
number of commenters supported EPA’s
compliance schedule and rationale.
Other commenters supported extending
the compliance deadlines to later dates.
Many commenters questioned the
technical feasibility of achieving the
required reductions by the 2012 and
2014 dates. EPA’s responses to those
comments are discussed below in
section VII.C.2.
Other commenters provided policy
and legal arguments for allowing states
to develop SIP alternatives to the FIP,
and to build time for that SIP
development and review process into
the compliance schedule. For example,
some commenters asserted that the
requirement in the CAA for providing
reductions ‘‘as expeditiously as
practicable’’ must be balanced with
CAA provisions allowing states to
develop state implementation plans
prior to EPA imposing FIPs. EPA
responses to those comments are
discussed in section X.
Some commenters suggested that EPA
had the ability to leave CAIR in place
for a transition period, and by doing this
EPA could allow for a longer
compliance period for this rule. EPA
does not believe it would be
appropriate, in light of the Court’s
decision in North Carolina, to establish
a lengthy transition period to the rule
that will replace CAIR. Although the
Court decided on rehearing to remand
CAIR without vacatur, the Court
stressed its prior decision that CAIR was
deeply flawed and EPA’s obligation to
remedy those flaws. North Carolina, 550
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F.3d 1176. Although the Court did not
set a definitive deadline for corrective
action, the Court took care to note that
the effectiveness of its opinion would
not be delayed ‘‘indefinitely’’ and that
petitioners could bring a mandamus
petition if EPA were to fail to modify
CAIR in a manner consistent with its
prior opinion. Id. Given the Court’s
emphasis on remedying CAIR’s flaws
expeditiously, EPA does not believe it
would be appropriate to establish a
lengthy transition period to the rule
which is to replace CAIR.
As relates to PM2.5, EPA received a
number of comments on its proposal to
include a 2012 deadline to ensure that
emission reductions needed to reduce
PM2.5 be achieved ‘‘as expeditiously as
practicable.’’ Some commenters
supported EPA’s 2012 deadline. Other
commenters believed that it was
unnecessary and unwarranted for EPA
to impose emission reduction
requirements in advance of the 2014
attainment date. In light of the 2014
five-year attainment date for the 2006
PM2.5 NAAQS (with a possible
extension to 2019), and the possible
extension to April 2015 for the 1997
PM2.5 NAAQS, these commenters
believed EPA’s 2012 emission reduction
requirements for annual PM2.5 and NOX
were not necessary. EPA disagrees with
these commenters, for a number of
reasons. First, EPA notes (supported by
commenters) that there is a clear
statutory obligation to attain ‘‘as
expeditiously as practicable.’’ Second,
EPA notes that there are feasible
reductions available by 2012. Third,
EPA believes that the substantial health
and environmental benefits achieved by
the rule underscore the importance of
achieving the reductions as soon as
possible.
With respect to ozone, some
commenters noted that the proposed
rule required ozone reductions by 2012
for states impacting areas which EPA’s
analysis shows will attain the 1997
ozone NAAQS by 2014 without further
controls. Those commenters questioned
the importance of getting reductions in
such states and whether the 2012
deadline is necessary. EPA disagrees
with those comments. Except for
Houston, all ozone areas within the
region addressed by this rule have
attainment dates no later than 2013. In
effect, this means that emission
reductions needed to attain the 1997
ozone NAAQS must be in place by the
2012 ozone season. EPA believes that if
there are reductions available by 2012,
and those emission reductions have in
fact been identified, it is appropriate
and necessary to ensure that those
reductions are in place.
2. Compliance and Deployment of
Pollution Control Technologies
The power industry will undertake a
diverse set of actions to comply with the
Transport Rule at the start of 2012 and
another set of actions when companies
in Group 1 states comply with more
stringent SO2 budgets at the start of
2014. In 2012, the industry will largely
meet the rule’s NOX requirements by:
Operating an extensive existing set of
combustion and post-combustion
controls on fossil fuel-fired generators;
dispatching lower emitting units more
often; and installing and operating a
limited amount of relatively simple NOX
pollution controls in states not
previously subject to CAIR. For the SO2
requirements, EPA anticipates at a
minimum that coal-fired generators will
operate the substantial capacity of
advanced pollution controls already in
place or scheduled for 2012 use; some
units will also elect to burn lower-sulfur
coals; and the fleet will increase
dispatch from lower-sulfur-emitting
units as well as from natural gas-fired
generators. EPA provides a more
detailed explanation below of how fuel
switching to lower sulfur coals factored
in to the design of the final Transport
Rule.
By 2014, EPA’s budgets under the
Transport Rule will sustain previous
NOX and SO2 reductions as well as
account for reductions from additional
advanced NOX and SO2 controls that are
driven by other state and federal
requirements. In addition to these
reductions, companies in Group 1 states
are also projected to add a limited
amount of advanced SO2 controls in
2014 that will be discussed below.
EPA’s expectations are supported by
the IPM analysis reported in this rule’s
RIA (see Chapter 7). Notably, since EPA
has established a cap and trade control
system for lowering NOX and SO2
emissions, individual owners and
operators of covered units have some
flexibility in meeting the program’s
requirements as needed and are free to
find alternative ways to comply. The
RIA clearly shows a viable known
pathway for owners and operators to
comply at reasonable costs, although it
is not the only compliance pathway
possible under this flexible regulation
that could deliver the emission
reductions required under the rule.
Notably, by 2014 and beyond, the power
industry may also augment the
projected compliance efforts with
programs aimed at improving energy
efficiency.
Table VII.C.2–1—shows EPA’s
projection of the amount of existing
coal-fired generating capacity in
gigawatts (GW) that may retrofit various
systems for compliance with this rule.
TABLE VII.C.2–1—PROJECTED POTENTIAL AIR POLLUTION CONTROL (APC) RETROFITS FOR TRANSPORT RULE 59
Wet FGD
Dry FGD
DSI
SCR
January 1, 2012 .............................................................
January 1, 2014 .............................................................
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Capacity retrofitted by
.........................
5.7 GW ...........
.........................
0.2 GW ...........
.........................
3.0 GW ...........
.........................
0 GW.
EPA received proposal comments
expressing a concern about the
feasibility of deploying retrofit air
pollution control (APC) technologies in
the time frames available between the
final date of this rule and the
compliance dates. As discussed below,
EPA believes that it is feasible for the
electric power sector and its APC
supply chain to either make most of the
projected retrofits in time to meet the
2012 and 2014 compliance deadlines, or
to comply by other means.
59 GW: Gigawatts of capacity retrofitted; FGD:
Flue gas desulfurization (SO2 control); DSI: Dry
sorbent injection (SO2 control); SCR: Selective
catalytic reduction (NOX control); LNB/OFA: LowNOX burner and/or overfire air (NOX controls).
a. 2012 Power Industry Compliance
EPA’s analysis of emission reductions
available in 2012 assumes year-round
operation of existing post-combustion
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LNB/OFA
improvements
10 GW
pollution controls in states covered for
PM2.5 and ozone-season operation of
NOX post-combustion controls in states
covered for ozone. EPA also modeled
emission reductions available in 2012 at
the $500/ton threshold for SO2, $500/ton
for annual NOX, and $500/ton for ozoneseason NOX.
For SO2, EPA believes that reductions
associated with the following methods
of control are available and will be used
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as compliance strategies to meet the
2012/2013 budgets: (1) Operation of
existing controls year-round in PM2.5
states, (2) operation of scrubbers that are
currently scheduled to come online by
2012, (3) some sources switching to
lower-sulfur coal (see section VII.C.2.c
that follows), and (4) changes in
dispatch and generation shifting from
higher emitting units to lower emitting
units. EPA modeling and selection of a
$500/ton cost threshold includes all
existing and planned controls operating
year round (items 1 and 2). It also
reflects an amount of coal switching and
generation shifting that can be achieved
for $500/ton. This set of expected
actions was confirmed in the detailed
modeling of EPA’s final remedy in the
RIA and can be reviewed there.
The power sector is already strongly
positioned to achieve the Transport
Rule state budgets presented in section
VI.D through at least three distinct
strategies. First, the sector will optimize
its use of the large proportions of
advanced pollution controls already
present throughout the fleet. Second,
the sector will take advantage of the
substantial new pollution control
technology that is already on the way
for deployment by 2012. Third, the
remainder of the fleet will flexibly adopt
the most economic low-emitting fuel
mix available at each unit to deliver
cost-effective emission reductions
complementing the reductions achieved
from optimized use of the fleet’s
pollution control technology. The state
maps in Chapter 7 of this rule’s
Regulatory Impact Analysis demonstrate
how these emission reduction strategies
for 2012 will build off of the sector’s
historic trend toward cleaner generation
profiles. Also, the detailed unit-level
projection files from EPA’s IPM power
sector modeling of the Transport Rule
remedy (found in the docket for this
rulemaking) show how EGUs adopt
these strategies to not only reach the
2012 budgets, but in fact in many states
overcomply with the budgets and build
up a bank of allowances under the
programs for future flexibility.
The following paragraphs illustrate
the degree to which the existing fleet is
already prepared to adopt these
emission reductions in 2012 in order to
attain the required emission reductions
for SO2, annual NOX, and ozone-season
NOX under the Transport Rule. More
specifically, the illustrative paragraphs
demonstrate emission reduction
pathways for coal capacity to optimize
or increase operation of existing control
technology, timely implement existing
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plans to bring additional control
technology on line, and to costeffectively make use of lower-emitting
fuel alternatives.
Of the 240 GW of coal capacity in the
Transport Rule region covered for fine
particles, approximately 110 GW—more
than 45 percent—had existing advanced
pollution control for SO2 already in
place in 2010, including scrubbers
(FGD), dry sorbent injection (DSI), or
circulating fluidized bed boilers. Of this
controlled coal capacity, EPA expects a
significant portion will improve
emission rates through either increased
use of control technology and/or
additional fuel switching. EPA notes
that an additional 39 GW of advanced
SO2 controls in the region are scheduled
to come online over the 2010–2012
timeframe and will also assist in
meeting 2012 emission reduction
requirements. Thus, by 2012 more than
half of affected coal capacity—152
GW—will be operating with advanced
SO2 control equipment. Additionally,
EPA expects approximately 40 GW of
uncontrolled coal capacity in the region
to take advantage of the existing coal
supply infrastructure, possibly
switching coal use or coal blending
behaviors to make cost-effective
reductions in SO2 emission rates where
economic to respond to the Transport
Rule 2012 emission reduction
requirements.
EPA notes that approximately 136 GW
of the 240 GW—more than 56 percent—
of coal capacity in the Transport Rule
region covered for fine particles had
existing advanced pollution control for
NOX already in place in 2010, including
selective catalytic reduction (SCR),
selective non-catalytic reduction
(SNCR), or circulating fluidized bed
boilers. Of this capacity, EPA
anticipates a significant portion will
improve their NOX emission rate
through increased operation of these
existing controls. Additionally, EPA
notes that an additional 21 GW of SCR
and 4 GW of enhanced combustion
controls (including low-NOX burners
and overfire air) are scheduled to come
online in the region during the 2010–
2012 timeframe, bringing the total
region’s coal capacity operating with
NOX emission reduction technology to
158 GW (more than 65 percent of total
coal capacity in the Transport Rule fine
particle region). EPA also projects that
approximately 13 GW of coal capacity
will make some reduction in their NOX
emission rates by enhancing
performance of existing combustion
controls or SNCR, or by fuel switching.
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In the Transport Rule states covered
under the ozone-season program,
approximately 145 GW of the 260 GW
(more than 55 percent) of coal capacity
had existing NOX control technology in
place in 2010. EPA expects a significant
portion of that capacity to achieve
emission reductions during the 2012
ozone-season through improved
operation of SCR. Additionally, in the
Transport Rule ozone region there will
be approximately 21 GW of additional
advanced NOX control installations and
7 GW of additional combustion control
improvements or installations coming
online during the 2010 to 2012 time
frame. EPA projects that 17 GW of coal
capacity in the Transport Rule ozone
region will reduce NOX emission rates
by enhancing performance of existing
combustion controls or SNCR or by fuel
switching.
For NOX, EPA has also concluded that
it is appropriate to require reductions
through a limited amount of combustion
control improvements, and in some
cases, retrofits such as low-NOX burners
(LNB) and/or overfire air (OFA). EPA
recognizes that the 6-month time frame
between rule finalization and start of the
first compliance period would not allow
for the installation of a major postcombustion NOX control such as SCR.
Assumed improvements and retrofits for
the January 1, 2012 deadline for annual
NOX reductions therefore only involve
the much simpler LNB/OFA control
modifications or installations.
Alternatively, some plant owners might
choose to achieve NOX reductions in a
similar time period through an even
simpler retrofit—SNCR.60
Although the improvements, and in
some cases, installation of combustion
controls would be an economic means
of achieving emission reductions, these
specific controls are not required for
compliance purposes under the final
Transport Rule remedy. Individual
sources may comply through other
measures (such as purchasing additional
allowances) in the event that it takes
more than 6 months for installation of
a given combustion control. The vast
majority of covered sources already
have combustion controls installed;
therefore, the NOX reductions associated
with these incremental control
improvements and installations are
small.
60 David L. Wojichowski, SNCR System—Design,
Installation, and Operating Experience https://
www.netl.doe.gov/publications/proceedings/02/scrsncr/wojichowski-1.pdf.
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Based on the Transport Rule’s
geography, EPA estimates that
approximately 10 GW of coal-fired units
may improve, and in some cases, install
LNB/OFA specifically in reaction to the
Transport Rule NOX caps. EPA reflects
the effects of these installations in the
2012 annual and ozone-season NOX
budgets, which would yield reductions
of approximately 28,000 tons of annual
NOX and 14,000 tons of ozone-season
NOX. EPA assumes these controls are
cost effective at $500/ton and that they
should be incentivized through budgets
given the 2013 attainment deadline for
ozone areas classified as ‘‘serious.’’
Once installed, LNB/OFA operates any
time the boiler is fired and thus yields
NOX reductions beyond the ozone
season alone.
In the proposal’s LNB technical
support document,61 EPA observes that
LNB and/or OFA installations, burner
modifications, or other NOX reduction
controls would likely have to be
installed during fall 2011 or spring 2012
outages in order to achieve significant
reductions for 2012. While this 6-month
schedule is aggressive, industry has
shown that it can be met. For example,
Limestone Electric Generating Station
Unit 2, an 820 MW tangentially-fired
lignite unit, was retrofitted with Foster
Wheeler’s Tangential Low NOX (TLN3)
system in less than six months,
including engineering, fabrication,
delivery and installation.62 Harlee
Branch Unit 4, a 535 MW cell-fired unit,
was retrofitted with Riley Power’s lowNOX Dual Air Zone CCV burners on a
similar schedule.63 These are
tangentially-fired and wall-fired units,
respectively, representative of the unit
types that might make LNB/OFA
improvements for compliance with this
rule. Although such 6-month schedules
can be achieved on some units, under
favorable circumstances, historical
projects suggest a more typical schedule
would be 12 to 16 months for the
contractor’s portion of the work.64 A
plant owner’s project planning and
procurement work in advance of a
contract award would typically involve
several additional months. On the other
hand, there are other approaches that
can also be implemented in a short time
frame to achieve significant NOX
reduction. As mentioned above,
relatively simple SNCR systems can be
48281
installed quickly; and the re-tuning or
upgrading of existing combustion
control systems can often provide
significant NOX reductions and can be
performed quickly.65
As stated above, EPA believes that
LNB/OFA modifications or retrofits
would be possible during the 6-month
interim between rule signature and the
start of the first compliance period,
particularly for those ‘‘early movers’’
who have initiated LNB projects based
on the proposed rule. However, as
shown in Table VII.C.2–2, below, even
if all LNB modifications or installations
are delayed until the beginning of the
2012 ozone season, the reductions only
represent 1 percent of most covered
states’ annual NOX budgets, and no
more than 11 percent of any affected
state’s annual NOX budget. Under such
a scenario, these delayed reductions
would still be well within the 18
percent variability limit applied to each
state’s annual NOX budget. In light of
this limited consequence and the
supporting material above, EPA
includes LNB-driven NOX reductions in
both annual and ozone-season NOX
budgets for 2012.
TABLE VII.C.2–2—EARLIEST REDUCTIONS ASSUMED FROM LNB INSTALLATIONS IN THE TRANSPORT RULE STATES
SUBJECT TO THE ANNUAL NOX PROGRAM *
NOX reductions
from LNB
operation from
January–April
(tons)
Annual NOX
state budget
(tons)
Percent of budget met by earliest
LNB reductions
(percent)
Georgia ............................................................................................................................
Iowa .................................................................................................................................
Kansas .............................................................................................................................
Minnesota ........................................................................................................................
Nebraska ..........................................................................................................................
646
567
2,131
2,303
3,008
62,010
38,335
30,714
29,572
26,440
1
1
7
8
11
Region-wide Total .....................................................................................................
8,656
1,245,869
1
* Based on EPA IPM Analysis of Final Transport Rule.
EPA projects that compliance with
2014 requirements for NOX will result
largely from operation of existing and
future controls required by state and
other federal requirements, as well as
the appropriate dispatch of the electric
generation fleet. EPA does not project
additional NOX pollution control
retrofits aside from about 10 GWs of
combustion control improvements or
retrofits projected for the 2012
compliance period. To comply with the
rule’s SO2 requirements, EPA projects
that the power industry will rely on
existing controls, operate newly
installed advanced controls necessary
for other binding state and federal
requirements, rely more on relatively
lower sulfur coals, and dispatch loweremitting generation units. In Group 1
states, industry is projected to increase
switching to lower sulfur coals and
install a limited amount of additional
scrubbers and other advanced pollution
control technology. EPA’s assessment of
the industry’s ability to install SO2
pollution controls in 2014 and
undertake the projected coal switching
follows below.
EPA’s modeling of least-cost
compliance with the state budgets under
the Transport Rule projects
approximately 5.9 GW of FGD systems
and lesser amounts of other
technologies will be retrofitted by 2014
61 Technical Support Document (TSD) for the
Transport Rule, Docket ID No. EPA–HQ–OAR–
2009–0491, Installation Timing for Low NOX
Burners (LNB).
62 R. Pearce, J. Grusha, Reliant Energy Tangential
Low NOX System at Limestone Unit 2 Cuts Texas
Lignite, PRB and Pet Coke NOX, https://
www.fwc.com/publications/tech_papers/files/
tp_firsys_01_02.pdf.
63 B. Courtemanche, et al., Reducing NO
X
Emissions and Commissioning Time on Southern
Company Coal Fired Boilers With Low NOX
Burners and CFD Analysis, https://
www.babcockpower.com/pdf/t-182.pdf.
64 M. O’Donnell, Babcock & Wilcox Company,
(personal communication with EPA staff, February
22, 2011).
65 N.C Widmer, et al., Coal Power, October 8,
2009, https://www.coalpowermag.com/ops_and_
maintenance/Zonal-Combustion-Tuning-SystemsImprove-Coal-Fired-Boiler-Performance_226.html.
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for compliance with the Transport
Rule.66 67 EPA’s schedule assumptions
for these larger more complex projects
were developed in an earlier study and
mentioned in the proposal: 27 months
for retrofitted wet FGD and 21 months
for SCR.68 Note that a dry FGD system,
due to its relatively simpler
configuration and lesser cost, would
typically take somewhat less time to
retrofit than wet FGD.
As discussed below, EPA believes that
its schedule assumptions remain
reasonable expectations for sources that
have completed most of their
preliminary project planning and can
quickly make commitments to proceed.
These schedules do not include the
extensive time that some plant owners
might spend in making a decision on
whether or not to retrofit. They do
include the time needed to make a final
confirmation of the type of technology
to be used at a particular site, to prepare
bid requests, award contracts, perform
engineering, obtain construction and
operating permits (in parallel with
project activities), perform construction,
tie-in to the existing plant systems, and
perform integrated systems testing.
EPA received comments on the
proposed rule indicating that some past
single-unit APC retrofits had
considerably longer schedules, with a
few exceeding 48 months. EPA
engineering staff have extensive
experience with power plant and APC
system design, construction, and
operation. Based on that experience,
EPA can observe that in the absence of
a compelling deadline or major
economic incentive, many large project
schedules are considerably longer than
necessary. Given further observations as
explained below, EPA believes it is
66 Nearly all of the 5.9 GW of FGD retrofits are
comprised by some 12 units at 7 plants (Beckjord,
Muskingum River, Homer City, Rockport, Kammer,
Danskammer, and Will County).
67 As noted elsewhere in this preamble, the
projected impacts of this final rule presented in the
preamble do not reflect minor technical corrections
to SO2 budgets in three states (KY, MI, and NY) and
assumed preliminary variability limits that were
smaller than the variability limits finalized in this
rule. EPA conducted sensitivity analysis factoring
in these corrections; the results of this analysis
include a small increase of about 700 MW of
additional wet FGD retrofit projected for 2014. This
projected additional retrofitting capacity is already
required to retrofit under a consent decree and
should therefore have already conducted advanced
retrofit planning. EPA therefore believes that this
incremental projected retrofit behavior (factoring in
the technical corrections made after the main
impact analyses were conducted) is feasible by 2014
for the same reasons presented in this section
regarding the projected retrofit behavior from the
main analysis of the final rule.
68 EPA, Engineering and Economic Factors
Affecting the Installation of Control Technologies
for Multipollutant Strategies; EPA–600/R–02/073
October 2002.
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reasonable to expect that almost all
future APC retrofits can be completed
far more quickly than they were in
recent history. EPA’s perspective on this
matter derives in part from a
comparison of longer APC schedules (as
provided by some commenters) to the
project schedule for an entire new coalfired unit, including its APC systems.
Springerville Unit 3, for example, is a
new 400 MW subbituminous coal-fired
unit with SCR and dry FGD that became
operational in July 2006, some 33
months after the turnkey engineeringconstruction contractor was given a
notice to proceed with engineering.69
Springerville was clearly on an
accelerated schedule, as its original
planned schedule was about 38 months.
Another example is Dallman Unit 4, a
high-sulfur bituminous coal-fired 200
MW unit with SCR, fabric filter, wet
FGD, and wet ESP. Dallman Unit 4 was
first synchronized in May 2009, several
months ahead of schedule, and about 36
months after its turnkey contractor
placed initial major equipment orders.70
The main point here is that recent APC
project schedules, and those of large
complex power projects, can be
significantly accelerated. Because the
scope and complexity of the work
involved for an entire new coal unit and
its APC systems is perhaps five times
greater than that of a retrofit wet FGD
system alone, EPA believes it is
reasonable to expect that even the most
complex retrofit APC project can be
significantly accelerated as well.
Additional factors are discussed below
that further support the feasibility of
installing by 2014 the 5.9 GW of FGD
retrofits projected for this rule.
Although IPM modeling provides
reliable estimates on a regional basis,
and cannot be as accurate at the level of
individual plants or units, it is
informative and relevant to consider
IPM’s plant level projections in this
case. Although the IPM-projected
retrofits named below may not actually
occur, IPM projects that they would be
economic and would allow industry to
meet the tighter SO2 emission standards
in Group 1 states in 2014. EPA notes
that the owners of the particular plants
mentioned below (Duke Energy, AEP,
Edison International) are large,
experienced, versatile utilities that have
done considerable advance planning
69 Best Coal-fired Projects, Springerville Unit 3
Expansion Project, Power Engineering, November
2006, https://www.powergenworldwide.com/index/
display/articledisplay/282547/articles/powerengineering/volume-111/issue-1/features/projectsof-the-year.html.
70 https://www.cwlp.com/electric_division/
generation/Dallman%204%20Power%20Plant%20
of%20the%20Year.pdf.
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and should also have above-average
flexibility to comply with state budgets
across their fleets. EPA would expect
such owners to have relatively little
difficulty in permitting and financing
FGD retrofits.
Of the Transport Rule-related FGD
retrofits, 0.2 GW is projected to use dry
FGD, which EPA expects to be simpler
and quicker to install than wet FGD.
Half of the 5.9 GW (Muskingum,
Rockport) has already been committed
under consent decrees to add controls or
retire; 71 and EPA reasonably believes
that significant preliminary project
planning work has already been done
for those projects. An additional 1,200
MW (Homer City) had completed
project planning and was ready to
proceed in 2007, before putting the
project on hold.72 The latter plant is
now facing EPA legal action and the
possibility of a required expeditious
FGD retrofit.73 Thus, of the 5.9 GW of
projected FGD retrofits resulting from
this rule, nearly 75 percent appears to
be in good position for an early start of
construction, and over 3 GW of that
would be bringing forward already
committed compliance start dates.
Any of the above mentioned potential
retrofits or any other unit that might
choose to retrofit FGD for a January
2014 compliance date will likely have to
use various methods to accelerate the
project schedule. Such methods could
include the use of parallel permitting,
overtime and/or two-shift work
schedules during construction, and 5- or
6-day work weeks instead of the 4-day
× 10-hour schedules often used to
minimize cost when time is not of the
essence. Increased use of offsite
modularization and pre-fabrication of
APC components could also shorten
schedules and reduce job hours.
EPA believes that the January 1, 2014
compliance date is as expeditious as
practicable for the sources installing
large, complex control systems. The
following additional observations
support EPA’s expectation that the
limited 5.9 GW of FGD retrofits can be
realized in the 30 month interim
between rule signature and the start of
2014:
• There are documented instances of
large, complex wet FGD retrofits being
deployed in less than 30-months
(excluding the time for owners’ project
71 https://www.epa.gov/compliance/resources/
decrees/civil/caa/americanelectricpower-cd.pdf.
72 https://www.businesswire.com/news/home/2006
0731005193/en/Contractors-Selected-InstallEmissions-Control-System-Pennsylvania.
73 https://www.epa.gov/Compliance/resources/
complaints/civil/caa/homercity-cp.pdf.
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planning). Examples are Killen Station
Unit 2,74 and Asheville Unit 1.75
• In 2009 the APC supply chain
deployed more than six times more GW
capacity of FGD and SCR controls than
the 5.9 GW of FGD that would be
deployed by 2014 under this Rule.
• The APC supply chain has seen a
2-year decline in deployments since its
peak in 2009, but in 2011 is nonetheless
putting into service about three times
more GW capacity of FGD and SCR
controls than the 5.9 of FGD that would
be deployed under this Rule.
• Because the supply chain has been
in decline, but remains quite active,
there are now adequate supply chain
resources available that can be quickly
reengaged to support a rapid
deployment of 5.9 GW of FGD.
EPA recognizes that the installation of
any amount of scrubbers in this short
time frame will require aggressive action
by plant owners and that the owners
who can meet this schedule will already
have done their project planning and
will be ready to place orders. An
example of such ‘‘early movers’’ was
seen in the power sector’s anticipation
of CAIR. EPA data indicate that solely
CAIR-driven FGD and SCR deployments
of about 6 GW occurred within two and
one-half years after CAIR’s finalization
in mid-2005, showing that at least 20
percent of the total CAIR-only controls
effort through a 2010 compliance date
was sufficiently planned for installation
to start before or immediately upon
finalization of the rule. EPA reasonably
expects that similar advance planning
has already been done for units that
would retrofit under this rule.
In the event that a particular control
installation requires additional time into
2014 to come online, EPA believes
compliance would not be jeopardized
given the ability of sources to purchase
allowances during that time. This
approach could be supported by some
sources with FGD that have the ability
to increase their SO2 removal above
historic rates, perhaps through relatively
low cost upgrades to improve scrubber
effectiveness, or by operating scrubbers
at higher chemistry ratios. The ability of
sources to temporarily or permanently
substitute dry DSI for FGD serves as
another backstop for any feasibility
issues regarding FGD. Note that the
updated modeling for this rule projects
74 Black & Veatch, https://www.bv.com/News_3_
Publications/News_Releases/2005/0503.aspx (start),
https://www.bv.com/wcm/press_release/07252007_
9767.aspx (completion).
75 PowerGenWorldwide, Projects of the Year,
January 1, 2007, https://www.powergenworldwide.
com/index/display/articledisplay/282547/articles/
power-engineering/volume-111/issue-1/features/
projects-of-the-year.html.
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the addition by 2014 of about 3 GW of
DSI for SO2 control using trona or other
sorbent. DSI is a relatively low capital
cost technology that readily can be
installed in the time frame available for
compliance.76 77
It should also be noted that most APC
retrofits will involve a source outage for
final ‘‘tie-in’’ of retrofitted systems to
existing systems, during which time
emissions from the affected units are
zero. For some sources, the duration of
this tie-in outage may effectively extend
the deadline by which all of the
projected emission reductions need to
occur.
Although EPA believes that
installation of 5.9 GW of FGD at
facilities by January 1, 2014 is feasible,
EPA also conducted an IPM sensitivity
analysis to examine a scenario in which
FGD retrofitting by 2014 is not allowed.
Results of EPA’s ‘‘no FGD build in
2014’’ analysis indicate that if the power
industry were subjected to the
requirements of this rule without an
FGD retrofit option for compliance until
after 2014, covered units would still be
able to meet the Transport Rule
requirements in every state while
respecting each state’s assurance level.
(See the docket to this rulemaking for
the IPM run titled ‘‘TR_No_FGD_
in2014_Scenario_Final.’’)
In this scenario without the
availability of new FGD by 2014,
sources in covered states complied with
the Transport Rule budgets by using
moderate additional amounts of DSI
retrofits, switching to larger shares of
sub-bituminous coal, and dispatching
larger amounts of natural gas-fired
generation in lieu of the FGD retrofits
that are projected as being most
economic under modeling of the
Transport Rule remedy. Because new
FGD capacity is included in EPA’s
projection of the least-cost set of SO2
emission reductions required in Group
1 states, the ‘‘no FGD’’ sensitivity
scenario did project higher system costs,
although these costs were still
substantially lower than the remedy
EPA modeled in the Transport Rule
proposal.
The ‘‘no FGD’’ analysis indicates that
while the ability of Group 1 states to
meet their 2014 SO2 budgets is
facilitated by FGD retrofits, they are by
no means required, nor is Transport
Rule compliance jeopardized by their
76 ICAC letter to Senator Carper, November 3,
2010, https://www.icac.com/files/public/ICAC_
Carper_Response_110310.pdf.
77 Assessment of Technology Options Available
to Achieve Reductions of Hazardous Air Pollutants,
URS Corporation, April 5, 2011, https://www.
supportcleanair.com/resources/studies/file/4-8-11URSTechnologyReport.pdf.
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48283
absence. Even under a scenario in
which sources fail to complete FGD
retrofits by 2014, sources in the affected
states would have other compliance
options available at reasonable cost to
meet the state’s budget requirements.
This analysis shows that Group 1 states
would be able to comply with their 2014
SO2 budgets by relying on other
emission reduction opportunities that
do not require FGD retrofits. EPA
analysis confirms that those alternatives
are feasible both in terms of cost and
timing.
Finally, EPA recognizes that, when
finalized later this year as currently
scheduled, the Mercury and Air Toxics
Standards (MATS) will require
significant retrofit activity at covered
sources in the power sector with a 2015
compliance date for that rule. EPA’s
projections of retrofit activity under the
final Transport Rule are highly
compatible with its projections of
retrofit activity under the proposed
MATS (which included the proposed
Transport Rule in its baseline). EPA
therefore anticipates that the Transport
Rule’s projected retrofit activity will not
only be the least-cost compliance
pathway to meeting state budgets in
2014 but will also accelerate emission
reductions subsequently required by the
effective date of MATS. The final
Transport Rule’s projected 2014 retrofit
installations will also further
incentivize the power sector to ramp up
its retrofit installation capabilities to
achieve broader deployment of the
projected pollution control retrofits
under the proposed MATS.
Considering all the reasons given
above, EPA has concluded that the 2014
requirements for SO2 emissions in the
states covered by the Transport Rule are
reasonable and can be met by the power
industry by a variety of means.
c. Coal Switching for SO2 Compliance in
2012 and 2014
Coal switching is another mechanism
which can be used along with operating
pollution controls in 2012 for
compliance. It will be a complementary
activity by many coal-fired units
alongside of operating pollution
controls and the addition of more
scrubbers and DSI in 2014.
In the proposal, EPA noted that coal
switching could serve as a compliance
mechanism for 2012. EPA requested
comment on the reasonableness of
EPA’s assumption that coal switching
will have relatively little cost or
schedule impact on most units. EPA
received substantial comment
suggesting that the coal switching and
coal blending projected by EPA
modeling are not feasible for all units,
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and that, if feasible, would often incur
a cost through the derating of the unit
associated with the switch to a lower
sulfur coal or coal blend. Additionally,
sources indicated that coal switching by
2012 would not always be possible in
the six month window between final
rule signature and start of compliance.
These feasibility concerns stemmed
from restrictions included in existing
coal supply contracts and from boiler
design constraints that may hinder coal
switching within a 6 month window.
EPA agrees with these concerns and
revised its IPM modeling to limit coal
switching capability in 2012 for
particular units that may have trouble
switching coals or coal blends in a six
month time frame. A cost adder was
also included in the IPM modeling for
coal switching to capture the potential
cost burden of deratings that might
accompany switching to a very low
sulfur subbituminous coal or coal blend.
A particular commenter concern
regarding switching to lower sulfur
within the eastern bituminous coals
related to a possible impact on the
performance of a cold-side electrostatic
precipitator (ESP). Some ESPs that
operate at acceptably high collection
efficiency when using a high- or
medium-sulfur bituminous coal may
experience some loss in collection
efficiency when a lower sulfur coal is
used. Whether this occurs on a specific
unit, and the extent to which it occurs,
would depend on the design margins
built into the existing ESP, the
percentage change in coal sulfur
content, and other factors. In any case,
industry experience indicates that
relatively inexpensive practices to
maintain high ESP performance on
lower sulfur bituminous coals are
available and can be used successfully
where necessary. These include a range
of upgrades to ESP components and flue
gas conditioning.78 EPA therefore
assumes that it will not be necessary for
units that switch from higher to lower
sulfur bituminous to make a costly
replacement of the ESP.
Coal switching as a SO2 compliance
option might also include switching
from bituminous to subbituminous coal.
EPA’s analysis does not assume that a
unit designed for bituminous can switch
to (very low sulfur) subbituminous coal
unless the unit’s historical data
demonstrate that capability in the past.
EPA assumes that units with that
demonstrated capability have already
made any investments needed to handle
78 Assessment of Technology Options Available
to Achieve Reductions of Hazardous Air Pollutants,
URS Corporation, April 5, 2011, https://www.
supportcleanair.com/resources/studies/file/4-8-11URSTechnologyReport.pdf.
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a switch back to the use of
subbituminous coal at a similar
percentage of its heat input as in the
past. For IPM analysis in the final rule
EPA also introduced a coal switching
option that assumes that units can
increase a historically low percentage
use of subbituminous to a ‘‘maximum’’
level, if economic. This option includes
an appropriate derate in output,
increase in heat rate, and additional
capital and operating costs. Details of
this and other IPM updates for this rule
are provided in the IPM Modeling
Documentation in the docket for this
rulemaking (‘‘Documentation
Supplement for EPA Base Case
v.4.10_FTransport—Updates for Final
Transport Rule’’).
Some commenters also expressed
concern with the assumption that coalswitching from lignite to subbituminous
is a cost-effective or feasible emission
reduction strategy, particularly at Texas
EGUs. EPA carefully considered these
comments and adjusted its modeling of
cost-effective reductions to address this
concern. Specifically, EPA made
adjustment in the model so that it
assumes coal-switching is not a
compliance option at the specific units
where commenters identified technical
barriers to subbituminous coal
consumption. The Transport Rule
emission budgets are based on this
adjusted modeling which does not
assume any infeasible coal-switching
from lignite to subbituminous. In
addition, EPA’s analysis of cost-effective
reductions in each state presented in
section VI.B shows that Texas is capable
of cost-effectively meeting its Transport
Rule emission budgets; however, EPA
also conducted sensitivity analysis that
shows Texas can also achieve the
required cost-effective emission
reductions even while maintaining
current levels of lignite consumption at
affected EGUs. More details regarding
this analysis, including a table
comparing key parameters between the
main Transport Rule remedy analysis
and this Texas lignite sensitivity, can be
found in the response to comments
document and the IPM model output
files included in the docket for this
rulemaking.
D. Allocation of Emission Allowances
Under the final rule, EPA distributes
a number of SO2, annual NOX, and
ozone-season NOX emission allowances
to covered units in each state equal to
the SO2, annual NOX, and ozone-season
NOX budgets for those states. These
budgets are addressed in section VI.D of
this preamble. This section discusses
the methodology EPA uses to allocate
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allowances to covered units in each
state.
As discussed later in section VII.D.2,
EPA is setting aside a base 2 percent of
each state’s budgets for allowance
allocations for new units, with 5 percent
of that 2 percent, or 0.1 percent of the
total state budget being set aside for new
units located in Indian country. To this
base 2 percent, EPA is setting aside an
additional percentage on a state-by-state
basis, ranging from 0 to 6 percent
(yielding total set asides of 2 percent to
8 percent), for units planned to be built.
The remainder of the state budget is
allocated to existing units. Tables VI.D.–
3 and VI.D.–4 in this preamble show the
SO2, annual NOX, and ozone-season
NOX budgets for each covered state
(without the variability limits). In
allocating allowances to existing and
new units, EPA distributes four discrete
types of emission allowances for four
separate programs: SO2 Group 1
allowances, SO2 Group 2 allowances,
annual NOX allowances, and ozoneseason NOX allowances.
In the SO2 Group 1 and SO2 Group 2
programs, each SO2 allowance
authorizes the emission of one ton of
SO2 in that vintage year or earlier and
is usable for compliance only in the
program for which the allowance was
issued. In the annual NOX program,
each annual NOX allowance authorizes
the emission of one ton of NOX in that
vintage year or earlier in that program.
In the ozone-season NOX program, each
ozone-season NOX allowance authorizes
the emission of one ton of NOX during
the regulatory ozone season (May
through September for this final rule) in
that vintage year or earlier for that
program.
In each of the four trading programs,
a covered source is required to hold
sufficient allowances (issued in the
respective trading program) to cover the
emissions from all covered units at the
source during the control period. EPA
assesses compliance with these
allowance-holding requirements at the
source (i.e., facility) level.
This section explains how, in this
final rule, EPA allocates a state’s budget
to existing units and new units in that
state. This section also describes the
new unit set-asides and Indian country
new unit set-asides in each state,
allocations to units that are not
operating, and the recordation of
allowance allocations in source
compliance accounts.
1. Allocations to Existing Units
This subsection describes the
methodology EPA will use in the FIPs
finalized in this action to allocate to
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existing units.79 The same methodology
will be used to allocate allowances to
existing units for all four trading
programs.
For the reasons explained below, EPA
has decided to base allocations made
under the FIPs on historic heat input,
subject to a maximum allocation limit to
any individual unit based on that unit’s
maximum historic emissions. This
methodology gives each existing unit an
allocation equal to its share of the state’s
historic heat input for all the covered
units in the program, except where that
allocation would exceed its maximum
historic emissions; this methodology
constrains the heat input-based
allocations from exceeding any unit’s
maximum historic emissions. Further
detail on the implementation of this
approach is provided in section
VII.D.1.c below as well as in the
Allowance Allocation Final Rule TSD in
the docket for this rulemaking. All
existing-unit allocations for 2012 will be
made pursuant to the FIPs. However, as
described in section X, states may
submit SIPs or abbreviated SIPs to use
different allocation methodologies for
allowances of vintage year 2013 and
later.
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a. Summary of Allocation
Methodologies and Comments
EPA took comment on three distinct
allocation methodologies for existing
units. The first—an emissions-based
option—was presented in the original
Transport Rule proposal (75 FR 45309).
The second and third—heat input
option 1 and heat input option 2—were
presented in a Notice of Data
Availability (76 FR 1113). EPA received
numerous comments on all three
options.
i. Emission-Based Allocation
Methodology
The emission-based option presented
in the original Transport Rule proposal
would base allowance allocations to
existing units on each covered unit’s
calculated emission ‘‘share’’ of that
state’s budget for a given pollutant
under the Transport Rule. The proposed
rule stated that ‘‘for 2012, each existing
unit in a given state receives allowances
commensurate with the unit’s emissions
reflected in whichever total emissions
amount is lower for the state, 2009
emissions or 2012 base case emissions
projections. In either case, the allocation
79 In this rule, existing units are defined as
covered units that commenced commercial
operation prior to January 1, 2010. As explained in
greater detail in Section VII.B. of this preamble,
EPA decided to use this definition to ensure that
EPA would have at least 1 full year of qualityassured data on which to base a unit’s allocation.
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is adjusted downward, if the unit has
additional pollution controls projected
to be online by 2012. * * * For states
with lower SO2 budgets in 2014 (SO2
Group 1 states), each unit’s allocation
for 2014 and later is determined in
proportion to its share of the 2014 state
budget, as projected by IPM’’ (75 FR
45309).
Many commenters objected to this
projected emission allocation
methodology. Commenters offered two
principle objections. First, they argued
EPA should not use unit-level model
projections to allocate allowances.
Second, they argued the use of any
emission-based allowance methodology
is improper. Many of these commenters
argued that instead of an emission-based
allocation methodology, EPA should use
a heat-input-based allocation
methodology.
Commenters’ objections to the use of
unit level model projections focused
primarily on the accuracy of such
projections. While many commenters
supported the use of modeling
projections in determining state
emission budgets, they argued that the
unit-level model projections were not
sufficiently accurate to use as a basis for
allocating allowances to individual
units. Among other things, they argued
that the modeling used for the proposal
did not recognize certain non-economic
factors that may cause individual units
to operate differently than the model
projects. Commenters also argued that
EPA’s modeling does not capture all upto-date contracts and other economic
arrangements made at the unit-level
which may affect operational decisionmaking. Some of these commenters
continued to support the use of an
emission-based allocation approach, but
urged EPA to use more up-to-date and
specific unit-level data in its modeling
projections. Others opposed the use of
any emission-based allocation approach.
EPA acknowledges that the model
may not, at this time, capture all
relevant operational decision factors for
each individual unit. EPA also
recognizes that there are unit-level
details of operational decision-making
and economic arrangements (such as
certain contracts for electricity sales)
that are private and thus unavailable to
EPA on an ongoing basis for modeling
purposes. EPA believes these potential
omissions would not have a significant
impact on EPA’s determination of
significant contribution at the state
level; however, EPA recognizes they
could conceivably have a significant
impact on projections at the individual
unit level. EPA thus agrees with
commenters that the unit-level emission
projections from its modeling may not
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reflect all possible operational decisions
at a given unit and are therefore not an
appropriate proxy measure to use as a
basis for allocating allowances to
individual units.
Many commenters also argued that,
even if the emission projections could
be adjusted to capture all known and
up-to-date unit-level operational factors,
EPA should not use any emission-based
allocation approach. They argued that
an emission-based approach should not
be used because it is not fuel-neutral.
That is to say, the type of fuel consumed
significantly affects the emissions from,
and therefore the allocation to, a given
unit under an emission-based approach.
Commenters argued that an approach
that is not fuel-neutral effectively
awards higher-emitting units.
Commenters also argued that a projected
emission-based approach should not be
used because it is not control-neutral. In
other words, whether or not a unit has
installed controls would significantly
affect the allocation for a given unit
under an emission-based approach.
Under an emission-based approach,
controlled units receive significantly
fewer allowances than uncontrolled
units. Such an approach, commenters
pointed out, effectively penalizes
sources who have taken action to reduce
emissions.
EPA acknowledges that an emissionbased approach would not be fuelneutral or control-neutral. EPA notes
that the DC Circuit rejected the fuel
adjustment factors that were used in
CAIR to adjust state budgets based on
the type of fuel burned at each covered
unit. North Carolina, 531 F.3d 918–21
(rejecting use of fuel adjustments in
setting state NOX budgets). While the
proposal’s allocation methodology did
not explicitly adopt ‘‘fuel adjustment
factors’’ for allocation purposes, EPA
recognizes that an emission-based
allocation methodology effectively
advantages or disadvantages units based
on the type of fuel they combust.
In addition, several commenters
argued that the proposal’s emissionbased methodology would
inappropriately reward the highest
emitters under the program with more
allowances than their lower-emitting
counterparts would receive. EPA
acknowledges that such a methodology
would allocate more allowances to units
whose emissions make up a larger share
of the proposed Transport Rule
programs’ state budgets. EPA notes that
because any allocation patterns under
the Transport Rule FIPs would be
established in advance of covered
sources’ compliance decisions (i.e.,
decisions regarding how much to emit
under the programs), covered sources
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cannot be ‘‘rewarded’’ by adjusting their
future emissions. However, EPA notes
commenters’ observations that the
proposal’s methodology would reduce
allocations to units that previously
installed pollution control technology or
invested in cleaner forms of generation
in anticipation of CAIR. EPA concluded
in review of these comments that the
proposed Transport Rule’s allocation
methodology unintentionally yielded
this distributional outcome. EPA
therefore considered alternative
allocation methodologies described
below.
A substantial portion of the
commenters who objected to the
proposal’s emission-based allocation
option urged EPA to consider historic
heat input based approaches. EPA
agreed it should accept comment on the
use of historic heat input-based
approaches and published a NODA to
provide an opportunity for comment on
two specific heat input options and the
allocations that would result from
application of those options to the
proposed Transport Rule state budgets.
ii. Heat Input Allocation Option 1
The first heat input option presented
by EPA in the NODA (‘‘Option 1’’)
allocates allowances to units based
solely on their historic heat input.
Under this option, EPA would establish
a 5-year historic heat input baseline for
each covered unit and allocate
allowances to sources at levels
proportional to the each unit’s share of
the total historic heat input at all
covered units in that state.
Numerous commenters supported the
use of a heat-input based allocation
methodology. These commenters stated
that basing allocations on historic heat
input has the following advantages over
the proposal’s emission-based allocation
methodology:
(A) For certain types of units, historic
heat input data may offer a better
representation of unit-level operation
than model projections of unit-level
emissions; furthermore, for all units,
historic heat input is typically
represented by quality-assured data
reported by sources from continuous
emission monitoring systems, which
strengthens its accuracy.
(B) Historic heat input data are
generally fuel-neutral in that they do not
generally yield higher allocations for
units burning or projected to burn
higher emitting fuels.
(C) Historic heat input data are
generally emission-control-neutral in
that they do not generally yield reduced
allocations for units that installed or are
projected to install pollution control
technology.
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Many commenters also argued that a
heat input-based allocation
methodology should be used because,
unlike the proposal’s emission-based
methodology, a heat-input based
methodology would be generally fuelneutral and control-neutral and would
rely on unit-level quality-assured data
instead of on modeling projections.
Several commenters expressed
support for specific aspects of heat
input option number one. From a
technical standpoint, commenters noted
that heat input option 1 relied on the
highest-quality and most transparent
data EPA had provided as a basis for
allocating allowances under the
Transport Rule programs. They argued
that the calculation methodology for
heat input option 1 is more readily recreated and understood by sources than
either the proposal’s methodology or
EPA’s application of the ‘‘reasonable
upper-bound capacity utilization factor
and a well-controlled emission rate’’ in
heat input option 2 (described in greater
detail below). They also pointed out that
it is similar to methodologies used in
previous trading programs, such as the
NOX Budget Trading Program (see 40
CFR 96.42(a) & (b) (calculating each
existing EGU’s allocation by multiplying
each unit’s historic heat input by 0.15
lb/mmBtu)). In addition, commenters
supported the reliance of heat input
option 1 on continuous emission
monitoring system (CEMS) data that are
reported to EPA and certified by the
source’s designated representative (DR)
as accurate and complete. In addition,
many commenters supported EPA’s use
of historic data without further
transformation by any calculation
factors created by EPA.
From a policy perspective,
commenters highlighted the fuel
neutrality and emission-control
neutrality aspects of heat input option 1.
They noted that this option does not, in
contrast to the proposal’s emissionbased methodology, penalize a source,
through a reduced allowance allocation,
for having chosen a generation
technology or emission control
technology that was more favorable to
public health and the environment. EPA
agrees with these observations. The
allocation pattern associated with this
option does not advantage or
disadvantage units based on either the
fuel consumed or the presence or
absence of a pollution control
technology. In this respect, it is a
neutral approach that does not ‘‘reward’’
high-emitting units or ‘‘penalize’’ lowemitting units, including, for example,
those units on which pollution control
technology was installed in anticipation
of CAIR.
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EPA agrees with the aforementioned
arguments from these commenters
regarding the technical and policy
merits of this heat input-based
allocation methodology. EPA believes
that the quality-assured heat input data
reported by EGUs under its programs
are among the most detailed and sound
unit-level data accessible by EPA. EPA
believes the calculation of any
individual unit’s share of this historic
heat input data is a straightforward,
clear, and simple calculation to perform,
such that EPA’s calculated allowance
allocations under this approach can be
relatively easily replicated.
EPA also agrees with commenters that
such data has previously supported
allowance allocation procedures for
highly successful program
implementation of the ARP and the NOX
Budget Trading Program (NBP). Notably,
Congress chose a heat input-based
allocation approach when authorizing
the ARP in title IV of the Clean Air Act,
suggesting that Congress viewed heat
input as a reasonable basis for
allocation. Additionally, EPA’s selection
of a heat input-based approach for the
NBP was not legally challenged,
implying that stakeholders generally
saw a heat input-based approach as
reasonable.
EPA also agrees with comments
observing that allocations made under
this heat input approach do not
advantage or disadvantage units based
on their choice of fuel combustion or
pollution control technology, and that
allocations under this approach would
thus be ‘‘fuel-neutral’’ and ‘‘controlneutral.’’ EPA also agrees with
commenters that unlike the proposed
rule’s emission-based methodology, this
heat input methodology does not yield
lower allocation to units that reduced
emissions in advance of the Transport
Rule relative to units that did not make
such emission reductions.
Other commenters objected to the use
of a heat-input based allocation
methodology. These commenters argued
that the allocation pattern associated
with a heat-input allocation
methodology would yield ‘‘windfall
profits’’—in the form of allowance
allocations greatly in excess of likely
emissions—for certain units,
particularly with regard to SO2
allowance allocations for units
combusting natural gas. EPA disagrees
with the characterization of the excess
allowances as ‘‘windfall profits.’’
Allocations based on heat-input alone
are fuel-neutral and control-neutral. The
characterization of the heat-input
allocation methodology as creating
‘‘windfall profits’’ for any unit is based
on the assumption that all units should
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be allocated allowances based on
emissions, not heat input. In arguing the
heat-input approach creates a
‘‘windfall’’ for some units, commenters
are assuming that the allocation of
allowances above a unit’s projected
emissions constitutes a ‘‘windfall’’—a
conclusion EPA does not accept. EPA
believes that under market-based
regulatory programs, it is appropriate to
base initial allowance allocations on a
neutral factor and allow the market to
determine the least-cost pattern of
emission reductions in each state to
achieve the reductions that address the
state’s significant contribution and
interference with maintenance under
the final Transport Rule programs. EPA
disagrees that future allowance
transactions (following a neutral-factor
initial allocation) in response to these
market forces can be characterized as
‘‘windfall profits.’’ As explained above,
EPA believes it is appropriate to allocate
allowances based on a neutral factor.
Commenters appear to ask EPA, instead
of allocating based on a neutral factor,
to consider the unit-level distributional
impacts of each allocation methodology
and to select an allocation methodology
on the basis of equity. EPA does not
believe it would be appropriate for the
agency to pick an allocation
methodology to achieve any particular
distributional outcome as such
considerations are not related to the
statutory mandate of CAA section
110(a)(2)(D)(i)(I). Instead, EPA believes
it is appropriate to allocate allowances
to sources covered by its trading
programs based on a neutral factor.
Furthermore, CAA section
110(a)(2)(D)(i)(I) requires prohibition of
certain emissions within a state (i.e., a
state’s significant contribution and
interference with maintenance). It does
not direct EPA to use any particular
methodology for allocating allowances
under a trading program designed to
ensure all such emissions are
prohibited. As such, EPA believes it is
appropriate to allocate allowances based
on a neutral factor representing fossil
energy content used to produce
electricity. Detailed considerations of
equity, as the DC Circuit reminded EPA,
are not related to the statutory mandate
of section 110(a)(2)(D)(i)(I). North
Carolina, 531 F.3d 921.
Some commenters objected to the use
of a heat input-based approach by
arguing that higher-emitting units
would not receive an initial allocation
sufficient to cover their emissions. EPA
does not believe it is reasonable to
expect initial allocations to cover each
unit’s emissions under a trading
program aimed at producing meaningful
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emission reductions. In its
administration of prior trading programs
such as the ARP and the NBP, EPA has
made initial allowance allocations using
a heat input-based approach, and
virtually all covered sources have
successfully complied at the end of each
compliance period by making costeffective emission reductions,
purchasing additional allowances
through robust markets to cover
emissions, or undertaking both types of
activities. EPA disagrees with
commenters’ arguments that allowance
allocations should be used to
compensate units with higher
emissions.
iii. Heat Input Allocation Methodology
Option 2
The second heat input option
presented by EPA for public comment
also would use historic heat input but
would apply a constraint to unit-level
allocations under certain circumstances.
Specifically, under this option unitlevel allocations would not be allowed
to exceed what EPA determines, based
on historic emissions and other factors,
to be the units’ ‘‘reasonably foreseeable
maximum emissions.’’
To apply this constraint, EPA first
would determine whether the allocation
to a unit under an unconstrained heatinput methodology would exceed that
unit’s maximum historic emissions of
the relevant pollutant since 2003 ‘‘in
order to reflect unit-level emissions
before and after the promulgation of the
CAIR’’ (76 FR 1115). Using this baseline
would enhance the neutrality of the
maximum historic emissions data
because it would capture the highest
emissions of the unit during that period
regardless of what fuels it combusted or
what pollution control devices were
installed and used at any particular time
during that period. In other words, a
unit’s allocation would not be reduced
due to a recent decision to switch fuels
or install pollution controls.
Second, for this option, EPA then
would adjust that maximum historic
emissions data by applying a ‘‘wellcontrolled rate maximum,’’ designed to
place ‘‘a reasonably foreseeable
maximum emissions level reflecting a
reasonable upper-bound capacity
utilization factor and a well-controlled
emission rate that all units (regardless of
the type of fuel they combust) can meet
for the pollutant’’ (76 FR 1115). This
option would constrain certain units’
allocations that, if based solely on
historic heat input, would be
determined by EPA to be ‘‘in excess of
their reasonably foreseeable maximum
emissions’’ under the Transport Rule
programs (76 FR 1115).
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As noted above, commenters offered
numerous arguments in favor of using a
historic heat input approach. These
arguments apply equally to heat input
option 1 and heat input option 2. EPA
also received numerous comments
comparing the two heat input options
presented.
Many commenters preferred heat
input option 1’s reliance purely on
historic data as compared with heat
input option 2’s reliance on that data
modified by the application of EPAdetermined ‘‘reasonable upper bound
capacity factors’’ and ‘‘well-controlled
emission rates.’’ Commenters also
criticized the complexity of these
modification factors in heat input
option 2. While EPA believes both
options represent viable approaches, the
Agency agrees with commenters that the
application of these factors increase the
complexity of allocation determinations
and would adjust unit-specific historic
data by applying EPA-created factors
generically determined for broad
categories of units.
Some commenters suggested that
EPA’s application of these modification
factors could also represent legal
vulnerabilities for the Transport Rule. In
particular, they were concerned that the
capacity factors and well controlled
emission rates presented as part of heat
input option 2 could be perceived as
arbitrary. While EPA does not agree that
these modification factors are arbitrary,
the Agency does recognize that
application of such EPA-created generic
factors in determining unit-specific
allocations increases the complexity of
the allocation approach and raises
issues regarding whether such generic
factors are appropriately applied to each
individual unit.
iv. General Comments on EPA’s
Authority To Allocate Allowances
Numerous commenters also noted
that EPA has generally broad authority
in selecting an allocation methodology
under CAA sections 110(a)(2)(D)(i)(I)
and 302(y).80 EPA agrees with
commenters that the Agency has broad
discretion in this area. Neither the CAA
nor the D.C. Circuit Court’s opinion in
North Carolina specifies a particular
methodology that EPA must use to
allocate allowances to individual units.
80 CAA section 302(y) defines the term ‘‘Federal
implementation plan’’ as ‘‘a plan (or portion
thereof) promulgated by the Administrator to fill all
or a portion of a gap or otherwise correct all or a
portion of an inadequacy in a State implementation
plan, and which includes enforceable emission
limitations or other control measures, means or
techniques (including economic incentives, such as
marketable permits or auctions of emissions
allowances), and provides for attainment of the
relevant national ambient air quality standard.’’
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CAA section 110(a)(2)(D)(i)(I) requires
prohibition of emissions ‘‘within the
state’’ that significantly contribute to
nonattainment or interfere with
maintenance and gives states broad
discretion to develop a control program
in a SIP that achieves this objective.
EPA has similarly broad discretion
when issuing a FIP to realize this
objective. Moreover, while the
definition of FIP in CAA section 302(y)
clarifies that a FIP may include
‘‘enforceable emission limitations or
other control measures, means or
techniques (including economic
incentives, such as marketable permits
or auctions of emissions allowances),’’
this section does not require EPA to use
any particular methodology to allocate
allowances under a FIP trading program.
In light of this lack of direction in the
CAA concerning allowance allocation,
EPA has broad discretion to select an
allocation methodology that is
reasonable and consistent with the goals
of CAA section 110(a)(2)(D)(i)(I).
The body of public comment makes it
clear that no allocation option could be
deemed satisfactory from the
perspective of all stakeholders. Public
comments from most states and
industrial stakeholders with a
substantial interest in how EPA
allocates allowances under the
Transport Rule FIPs expressed support
for an historical heat input-based
approach as opposed to the proposal’s
emission-based approach. Most
commenters favored this historical heat
input data basis as the most sound and
offered technical data corrections,
which EPA considered and generally
used in the final rule. EPA believes it is
reasonable to select a heat input-based
approach for the final Transport Rule
because this approach is consistent with
the rule’s statutory objectives and has
been found, when implemented in prior
trading programs, to be a credible,
workable allocation approach.
b. Final FIP Allocation Methodology
After consideration of all comments,
EPA decided to allocate allowances to
individual units based on that units’
share of the state’s historic heat-input,
but to ensure that no unit’s allocations
exceed that unit’s historic emissions.
EPA decided to use the allocation
methodology originally presented as
heat input option 2, modified in
response to public comments. EPA
decided to use heat input option 2 but
without the application of the
‘‘reasonable upper-bound capacity
utilization factor and a well-controlled
emission rate’’ factors. This allocation
approach reflects the Agency’s response
to extensive public comment on the
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options presented in the proposed
Transport Rule and subsequent NODAs
and is a logical outgrowth of those
actions. EPA is using this approach to
allocate allowances under the FIPs for
all four trading programs. Further
details on the calculation and
implementation of this approach are
provided below in section VII.D.1.c and
can also be found in the Allowance
Allocation Final Rule TSD in the docket
for this rulemaking.
The principal reasons for this
decision are:
• EPA believes that existing-unit
allowance allocation under the
Transport Rule should not generally
advantage or disadvantage units based
on the selection of fuels consumed or of
pollution controls installed at a given
unit in anticipation of either the Clean
Air Interstate Rule or the Transport
Rule, i.e., fuel or control decisions taken
from 2003 onward. An approach that
does not advantage or disadvantage
units in this way avoids allocating in a
way that would effectively penalize
units that have already invested in
cleaner fuels or other pollution
reduction measures that will continue to
deliver important emission reductions
under this rulemaking. The approach
selected in the final rule generally does
not penalize such units and is thus
generally fuel-neutral and controlneutral in its allocation determinations.
• EPA finds that the selected
approach maximizes transparency and
clarity of allowance allocations. EPA
has already made public the historic
heat input and historic emissions data
on which this approach is based, and its
application to calculate unit-level
allocations in each state under that
state’s emission budgets finalized in this
Transport Rule can be relatively easily
replicated.
• EPA finds that quality-assured
historic CEMS-quality data used to
implement this approach represent the
most technically superior data available
to EPA at the time of this rulemaking for
calculating unit-level allocations. The
selected approach relies on unmodified
historic data reported directly by the
vast majority of covered sources, whose
designated representatives have already
attested to the validity and accuracy of
this data. EPA agrees with commenters
that allowance allocations should be
based on quality-assured data to the
maximum extent possible. This
approach uses the most accurate data
currently available to EPA.
• Heat-input based approaches were
used to allocate allowances under both
the NOX Budget Trading Program and
the Acid Rain Program. Allocation
under these programs was readily and
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easily administered, and the programs
achieved or exceeded their
environmental goals. The selected
approach’s use of heat input as a basis
for allocations builds on prior legislative
and administrative approaches to
allowance allocations for trading
programs.
• EPA also finds that the selected
approach’s addition of a constraint to
heat input-based allocations where such
allocations would otherwise exceed a
unit’s maximum historic emissions is a
reasonable extension of a heat inputbased allocation approach. The
Transport Rule trading programs are
established to achieve overall emission
reductions in each covered state. As a
group, covered sources within each state
must make the necessary reductions
under these programs. In light of each
program’s goal to reduce each state’s
overall emissions, it is logical and
consistent with that goal that the
starting point for each source under
these programs—i.e., the initial
allocations of shares of the state budget
to covered units—be an amount of
allowances no greater than each unit’s
maximum historic emissions. Under the
trading programs, any source may emit
a ton of SO2 or NOX for which it holds
a corresponding allowance, which it
may acquire either by initial allocation
or by subsequent purchase, to the extent
consistent with the assurance provisions
(discussed elsewhere in this preamble)
that ensure achievement of the requisite
overall reductions in each state.
Consequently, the initial allocations to
the units at each source are the starting
point for each source’s efforts to comply
with the allowance-holding and
assurance provision requirements, but
do not determine the source’s strategies
for compliance and ultimate level of
emissions. EPA believes that a starting
point of unit-level heat input-based
allocations constrained not to exceed
each specific units’ maximum historic
emissions is reasonable and consistent
with the program goals of reducing
overall emissions in each state: Each
existing unit is allocated an amount that
either reflects reduced unit emissions or
does not exceed historic emissions, and,
from that starting point, the units, as a
group, reduce overall emissions to the
level required for each state. Conversely,
EPA believes that a starting point
allocating some units more than they
have ever emitted would be illogical in
programs aimed at reducing overall
emissions.
EPA believes that this selected
allocation methodology for the final
Transport Rule FIPs is within its
authority under the Clean Air Act.
Section 110(a)(2)(D)(i)(I) of the CAA
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requires that emissions ‘‘within a state’’
that significantly contribute to
nonattainment or interfere with
maintenance in another state be
prohibited. In the final Transport Rule,
EPA analyzed each individual state’s
significant contribution and interference
with maintenance and calculated
budgets that represent each state’s
emissions after the elimination of
prohibited emissions in an average year.
The methodology used to allocate
allowances in a state budget to
individual units in the state has no
impact on that state’s budget or on the
requirement that the state’s emissions
not exceed that budget plus variability.
Regardless of the allocation
methodology used, the state’s
responsibility for eliminating its
significant contribution and interference
with maintenance remains unchanged.
This is reflected by the fact that
allocations under each state’s budget,
regardless of how they are made, cannot
change that state’s budget. In sum, the
allocation methodology has no impact
on the final rule’s ability to satisfy the
statutory mandate of CAA section
110(a)(2)(D)(i)(I) to eliminate significant
contribution to nonattainment and
interference with maintenance.
Consistent with its broad authority in
CAA sections 110(a)(2)(D)(i)(II) and
302(y), EPA believes that data quality,
fuel-neutrality, control-neutrality,
transparency, clarity, consistency with
program goals, and successful
experience in previous trading programs
are reasonable factors on which to base
the selection of an allowance allocation
methodology for existing units for the
final Transport Rule. EPA believes that
the transparency and clarity of this
allocation approach builds credibility
with the public that the government is
distributing a public resource—i.e.,
allowances—precisely as stated in this
rulemaking, with clear execution that
can be relatively easily verified.
EPA also believes that the final
Transport Rule’s heat input-based
approach for existing units is consistent
with the goals of the Clean Air Act
because it allocates allowances to
existing units on the basis of a neutral
factor that does not advantage or
disadvantage a unit based on what fuel
the unit burns or whether or not a unit
has installed controls in anticipation of
these regulations. In contrast,
allocations under the proposal’s
emission-based methodology would
give a greater share of allowances to
units with higher emission rates, which
are generally responsible for a greater
share of a state’s total emissions.
Because these higher-emitting rate units
are generally responsible for a greater
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share of emissions, it follows that they
are also responsible for a greater share
of a state’s significant contribution to
nonattainment and interference with
maintenance. The proposal’s emissionbased allocation methodology would
disadvantage one of two otherwise
identical existing units if it invested in
emission reductions in anticipation of
the Clean Air Interstate Rule or this final
Transport Rule.
The heat-input allocation
methodology selected for the final
Transport Rule does not have this flaw.
In contrast to the proposal’s emissionbased allocation approach, the heat
input allocation methodology selected
by EPA yields a smaller proportion of
allowances relative to emissions to
higher-emission-rate units and a higher
proportion of allowances relative to
emissions to lower-emission-rate units.
For example, assume that in a state with
two units and in a baseline year, Unit
A combusts 100 mmBtu of heat input
and emits 1,000 tons while Unit B
combusts 100 mmBtu of heat input and
emits only 500 tons. Assume also that
this state’s future Transport Rule
emissions budget for this pollutant is
only 500 tons. Because Units A and B
each make up an even share of historic
heat input for the state, the final rule’s
heat input-based approach would
allocate the same share of allowances
(250 tons) to each unit. In this example,
Unit A’s initial allocation of 250 is a
smaller proportion of its historic
emissions (25 percent of its baseline
1,000-ton emissions), while Unit B’s
initial allocation of 250 is a larger
proportion of its historic emissions (50
percent of its baseline 500-ton
emissions). Therefore, Unit B’s ability to
emit fewer tons per mmBtu of heat
content used for generating electricity
(as compared with Unit A) results in
Unit B receiving a larger proportion of
its historic emissions as an initial
allocation share than Unit A receives.
This relative distributional pattern
yielded is consistent with the goals of
CAA section 110(a)(2)(D)(i)(I) because
under this distribution, higher-emitting
units, which are responsible for a
greater share of the state’s significant
contribution to nonattainment and
interference with maintenance, would
require relatively more allowances in
order to cover their pre-existing
emissions than would lower-emitting
units. EPA believes this initial
allocation pattern is an appropriate
reflection of the goals of CAA section
110(a)(2)(D)(i)(I).
The heat input-based allowance
methodology selected by EPA is fuelneutral, control-neutral, transparent,
based on reliable data, and similar to the
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allocation methodologies used in the
NOX SIP Call and Acid Rain Program.
For all these reasons, EPA determined
that it is appropriate to use a heat inputbased allocation methodology in this
rule.
In addition, this allocation
methodology is similar to an outputbased allocation approach, which would
base allocations on the quantity of
electricity generated (rather than energy
content combusted) and would also be
fuel-neutral, control-neutral, and able to
reward generation units that operate the
most efficiently. Many state and
industry commenters advocated using
an output-based approach due to its
reported strong value in promoting
efficiency. However, at this time EPA
does not have access to unit-level
output data that is as quality-assured or
comprehensive as its data sets on heat
input across the units considered.
Therefore, EPA is using a heat inputbased approach under the Transport
Rule in part due to its ability to serve
as a reasonable proxy for an outputbased standard using the most qualityassured data that EPA has to date.
In the NODA, EPA noted that final
state budgets and allocations may differ
from the proposed budgets and
allocations because EPA was still in the
process of updating its emission
inventories and modeling in response to
public comments, including comments
on IPM. Thus, unit-level allocations in
the NODA provided an indication of the
proportional share of a state’s budget
that would be allocated to individual
existing units if the alternative
methodologies were used. The
allocations made final today are based
on budgets that reflect the updated
modeling and comments received
during the comment period.
c. Calculation of Existing Unit
Allocations Under the Final Transport
Rule FIPs
Allocations under this final
methodology for each existing unit are
determined by applying the following
steps.
1. For each unit in the list of potential
existing Transport Rule units, annual
heat input values for the baseline period
of 2006 through 2010 are identified
using data reported to EPA or, where
EPA data is unavailable, using data
reported to the Energy Information
Administration (EIA). For a baseline
year for which a unit has no data on
heat input (e.g., for a baseline year
before the year when a unit started
operating), the unit is assigned a zero
value. (Step 2 explains how such zero
values are treated in the calculations.)
The allocation method uses a 5-year
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baseline to approximate a unit’s normal
operating conditions over time.
2. For each unit, the three highest,
non-zero annual heat input values
within the 5-year baseline are selected
and averaged. Selecting the three
highest, non-zero annual heat input
values within the five-year baseline
reduces the likelihood that any
particular single year’s operations
(which might be negatively affected by
outages or other unusual events) would
determine a unit’s allocation. If a unit
does not have three non-zero heat input
values during the 5-year baseline
period, EPA averages only those years
for which a unit does have non-zero
heat input values. For example, if a unit
has only reported data for 2008 and
2009 among the baseline years and the
reported heat input values are 2 and 4
mmBtus, respectively, then the unit’s
average heat input used to determine its
pro-rata share of the state budget is
(2+4)/2 = 3.
3. Each unit is assigned a baseline
heat input value calculated as described
in step 2, above, referred to as the ‘‘3year average heat input.’’
4. The 3-year average heat inputs of
all covered existing units in a state are
summed to obtain that state’s total ‘‘3year average heat input.’’
5. Each unit’s 3-year average heat
input is divided by the state’s total 3year average heat input to determine
that unit’s share of the state’s total 3year average heat input.
6. Each unit’s share of the state’s total
3-year average heat input is multiplied
by the existing-unit portion of the state
budget (i.e., the state budget minus the
state’s new unit set-aside and, if
applicable, minus the Indian country
new unit set-aside) to determine that
unit’s initial allocation.
7. An 8-year (2003–2010) historic
emissions baseline is established for
SO2, NOX, and ozone-season NOX based
on data reported to EPA or, where EPA
data is unavailable, based on EIA data.
This approach uses this 8-year historic
emissions baseline in order to capture
the unit-level emissions before and after
the promulgation of CAIR.
8. For each unit, the maximum annual
historic SO2 and NOX emissions are
identified within the 8-year baseline.
Similarly, the maximum ozone season
NOX emissions from the 8-year baseline
for each unit are identified. These
values are referred to as the ‘‘maximum
historic baseline emissions’’ for each
unit.
9. If a unit has an initial historic heatinput based allocation (as determined in
step 6) that exceeds its maximum
historic baseline emissions (as
determined in step 8), then its allocation
equals the maximum historic baseline
emissions for that unit.
10. The difference (if positive) under
step 9 between a unit’s historic heatinput-based allocation and its
‘‘maximum historic baseline emissions’’
is reapportioned on the same basis as
described in steps 1 through 6 to units
whose historic heat-input-based
allocation does not exceed its maximum
historic baseline emissions. Steps 7, 8,
and 9 are repeated with each revised
allocation distribution until the entire
existing-unit portion of the state budget
is allocated. The resulting allocation
value is rounded to the nearest whole
ton using conventional rounding.
Table VI.D–1 below provides an
illustrative application of the steps 1–10
in a hypothetical state.
TABLE VI.D–1—DEMONSTRATION OF ALLOCATIONS USING FINAL ALLOCATION METHODOLOGY IN A THREE-UNIT STATE
WITH AN 80-TON STATE BUDGET
Steps 1–6
Steps 7, 8, 9
Steps 1–9
reiterated
Step 10
Initial historic
heat inputbased allocation
Maximum
historic baseline
emissions
Revised historic
heat inputbased allocation
Final allocation
20
30
30
16
50
50
N/A
32
32
16
32
32
Unit A .......................................................................................................
Unit B .......................................................................................................
Unit C .......................................................................................................
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2. Allocations to New Units
EPA is finalizing—similar to the
proposal (75 FR 45310)—an approach to
allocate emission allowances to new
units from new unit set-asides in each
state. A ‘‘new unit’’ may be any of the
following: (1) A covered unit
commencing commercial operation on
or after January 1, 2010; (2) any unit that
becomes a covered unit by meeting
applicability criteria subsequent to
January 1, 2010; (3) any unit that
relocates into a different state covered
by the Transport Rule; 81 and (4) any
existing covered unit that stopped
operating for 2 consecutive years but
81 Existing- or new-unit allocations drawn from
the budget of the relocated unit’s original state are
replaced by new unit set-aside allocations from the
budget of the unit’s relocation state in order to
generally ensure that allocations are drawn from the
correct state budget.
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resumes commercial operation at some
point thereafter.
The proposed Transport Rule would
have required that owners and operators
initially request allowances from the
new unit set-aside when the unit first
became eligible for an allocation. EPA
now believes that it can identify which
units become eligible and when they
become eligible, based on information
provided in other submissions (e.g.,
certificates of representation,
monitoring system certifications, and
quarterly emissions reports) that the
final rule already requires such units to
make to EPA. EPA concludes that
requiring owners and operators to
submit requests of new unit set-aside
allocations would impose an
unnecessary burden on the owners and
operators, as well as on EPA, and
therefore EPA has removed this
requirement in the final rule.
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The following sections describe the
methodology in the final Transport Rule
for allocating to new units, how EPA
determined the size of new unit setasides in the final rule, and how EPA
has provided for allocations to new
units that locate in Indian Country.
a. New Unit Allocation Methodology
The proposal’s new unit allocation
methodology did not provide any
allocation for a new unit’s first control
period of commercial operation. Some
commenters expressed concern about
the lack of new unit allocations the first
year of commercial operation. In order
to address this concern, EPA is
modifying the new unit allocation
methodology in this final rule to include
allocations to new units for the first
control period in which the units are in
commercial operation, as well as for
control periods in subsequent years.
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The final rule’s allocation to new
units is performed in two ‘‘rounds.’’ The
first round is the same as the new unit
allocation procedures in the proposal
(except for elimination of the
requirements that owners and operators
request the allocations) and occurs
during the control period for which the
allocations are made. These first round
allocations are based on new unit
emissions during the prior control
period and are recorded in allowance
accounts in the Allowance Management
System for the units by August 1 of each
control period. For example, for the
2012 vintage year, ‘‘first-round’’
allocations would be made to new units
by August 1, 2012 based on their
emissions in the 2011 control period (as
monitored and reported in accordance
with Part 75 of the Acid Rain Program
regulations). If the new unit set-aside is
insufficient to accommodate first round
allocations reflecting all new units’
prior control period emissions, the first
round allocations are made pro rata to
new units based on their share of total
new unit emissions in the prior control
period.
The second round of allocations
accommodates new units that come
online during the control period for
which the allocations are made and did
not therefore receive any allocation in
the first round. The second round also
accommodates new units that come
online partway into the prior control
period and therefore received an
allocation in the first round that did not
extend to cover operations in a full
control period. This second round of
new unit allocation is therefore
applicable only to new units coming
online either during the control period
of the allocation or during the control
period immediately prior. New units
coming online earlier than the previous
control period only receive first-round
allocations from the new unit set-asides,
as first-round allocations to those units
are based on operational data spanning
an entire control period.
Second-round allocations are based
on new unit emissions during the same
control period as the vintage year of the
allowances allocated. For example, for
the 2012 vintage year, ‘‘second-round’’
allocations are based on the difference
between the new unit’s emissions in the
2012 control period and the new unit
allocation (if any) that the unit received
in the first round of allocations. For a
unit coming online in 2012, this amount
equals its total emissions during the
2012 control period. For a unit coming
online in 2011, this amount equals its
incremental emissions in 2012 beyond
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its emissions in 2011, as such a unit
would have already received a firstround allocation from the new unit setaside based on its emissions in 2011.
Second-round allocations are recorded
in allowance accounts by November 15
for the NOX ozone season trading
program (ahead of the December 1
compliance deadline) and by February
15 of the following calendar year for
NOX and SO2 annual trading programs
(ahead of the March 1 compliance
deadline).
This methodology only allocates in
the second round whatever allowances
remain in the new unit set-asides after
the first-round allocations have been
recorded. If the new unit set-aside
available for second round allocations is
insufficient to accommodate allocations
based on the difference between control
period emissions and any first round
allocations for the units involved, then
the second round allocations are made
pro rate to the new units based on their
share of the total of such differences.
b. Determination of New Unit SetAsides
The proposed Transport Rule
identified new units using a threshold
online date of January 1, 2012, whereas
the final Transport Rule uses a
threshold online date of January 1, 2010.
As explained above, EPA adjusted this
cutoff date because the final Transport
Rule’s allocation methodology for
existing units requires that EPA possess
at least 1 full year of historic data in
order to calculate allocations. As a
consequence, EPA recognizes that the
proposal’s methodology to determine
the size of the new unit set-asides based
only on new EGUs forecast by the model
would fail to account for known EGUs
that have come online, or are planned
to come online, after January 1, 2010.
Therefore, EPA has modified its
approach to determining the size of the
new unit set-asides in the final rule to
account for both ‘‘potential’’ units (i.e.,
those that are not yet planned or under
construction but are projected by
modeling to be built) and ’’planned’’
units (i.e., those that are known units
with planned online dates after January
1, 2010). EPA uses the distinction
between ‘‘potential’’ and ‘‘planned’’
new units to determine the ultimate size
of each state’s new unit set-aside (as a
percentage of that state’s budgets for
each pollutant covered); however, the
new unit allocation methodology
described above applies the same to
‘‘potential’’ and ‘‘planned’’ new units.
The first step of EPA’s analysis to
determine the new unit set-asides
accounts for likely future emissions
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from potential units, and its
methodology is taken directly from the
Transport Rule proposal but reflects
updated modeling (see ‘‘Allowance
Allocation to Existing and New Units
Under the Transport Rule Federal
Implementation Plans’’ TSD for detailed
findings). This analysis informed EPA’s
decision to establish a minimum new
unit set-aside size of 2 percent of each
state’s budget for each pollutant that is
configured to accommodate future
emissions from potential units.
For the final rule, EPA augmented its
new unit set-aside determination to
account for ‘‘planned’’ units through an
additional step. Because the location of
these ‘‘planned’’ units is known and
identified in EPA modeling, this second
step is a state-specific modification of
the size of the new unit set-asides. That
is, EPA only increased new unit setasides above the 2 percent minimum
established in the first step for states
that had additional known units coming
online between January 1, 2010, and
January 1, 2012.
The increases made to the new unit
set-asides for these planned units reflect
the projected emissions from these
units. Therefore, if the expected
emissions of a given pollutant from all
‘‘planned’’ new units in a given state
were equal to 3 percent of that state’s
budget for that pollutant, then EPA
added that amount to the base 2 percent
new unit set-aside (creating a
hypothetical new unit set-aside of 5
percent for that pollutant in that state).
See ‘‘Allowance Allocation to Existing
and New Units Under the Transport
Rule Federal Implementation Plans’’
TSD for detailed results showing how
EPA determined the size of each new
unit set-aside reflecting the application
of both of the steps described above.
This approach to determining the size of
state new unit set-asides is a logical
outgrowth of the proposal, the NODA on
allowance allocations, and updated
modeling results. In fact, EPA received
comments that using a January 1, 2010
cutoff date for distinguishing between
existing and new units would result in
the new unit set-aside, as proposed,
being insufficient to meet the needs of
units already under construction. EPA
believes that the approach adopted in
the final rule results in new unit setasides that reasonably accommodate the
foreseeable emissions from both
planned and potential new units in each
state.
The new unit allocation percentages
for each state are shown in Table
VII.D.2–1.
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TABLE VII.D.2–1—PERCENTAGE OF STATE EMISSION BUDGETS FOR ALLOWANCES IN STATE NEW UNIT SET-ASIDES
Annual SO2
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Alabama .......................................................................................................................................
Arkansas ......................................................................................................................................
Florida ..........................................................................................................................................
Georgia ........................................................................................................................................
Illinois ...........................................................................................................................................
Indiana .........................................................................................................................................
Iowa .............................................................................................................................................
Kansas .........................................................................................................................................
Kentucky ......................................................................................................................................
Louisiana ......................................................................................................................................
Maryland ......................................................................................................................................
Michigan .......................................................................................................................................
Minnesota ....................................................................................................................................
Mississippi ....................................................................................................................................
Missouri ........................................................................................................................................
Nebraska ......................................................................................................................................
New Jersey ..................................................................................................................................
New York .....................................................................................................................................
North Carolina ..............................................................................................................................
Ohio .............................................................................................................................................
Pennsylvania ................................................................................................................................
South Carolina .............................................................................................................................
Tennessee ...................................................................................................................................
Texas ...........................................................................................................................................
Virginia .........................................................................................................................................
West Virginia ................................................................................................................................
Wisconsin .....................................................................................................................................
c. Procedures for Allocating New Unit
Set-Asides
For the first round of new unit setaside allocations, the Administrator will
promulgate a notice of data availability
informing the public of the specific new
unit allocations and provide an
opportunity for submission of objections
on the grounds that the allocations are
not consistent with the requirements of
the relevant final rule provisions. A
second notice of data availability will
subsequently be promulgated in order to
make any necessary corrections in the
specific new unit allocations. As
discussed elsewhere in this preamble,
the final rule establishes a different
schedule for promulgation of these
notices of data availability than the
proposed rule. In particular, a single set
of deadlines (i.e., for the first notice in
the first round of allocations, June 1 of
the year for which the new unit
allocations are described in the notice
and, for the second notice of the first
round, August 1 of that year) for
promulgation of the notices is
established for all of the Transport Rule
trading programs. EPA believes that
these deadlines will provide sufficient
time for EPA to obtain final emissions
data for the prior year for the units
involved and to calculate the allocations
and promulgate the notices. Further, the
approach of using the same deadline for
all of the Transport Rule trading
programs will simplify EPA’s
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implementation and reduce the
complexity of the process for source
owners and operators.
For the second round of new unit setaside allocations, the Administrator will
also promulgate two notices of data
availability. However, the deadlines for
the notices differ for the NOX ozone
season trading program and for the SO2
and NOX annual trading programs
because control period emissions data
(used in making second round
allocations) become available sooner,
and the compliance deadline for
holding allowances covering emissions
is sooner, in the NOX ozone season
trading program. The control period in
the NOX ozone season program ends on
September 30, and fourth quarter
emissions reports must be submitted to
EPA by October 30, while the control
periods in the SO2 and NOX annual
programs end on December 31 and
fourth quarter emission reports are due
by January 30. Further, in order for the
second round allocations to be available
to be used for compliance with the
allowance-holding requirement, the
second round needs to be completed
before the compliance dates, which are
December 1 in the NOX ozone season
program and March 1 in the SO2 and
NOX annual programs. Consequently,
for the NOX ozone season program the
Administrator will promulgate by
September 15 a notice of data
availability identifying the units eligible
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Annual NOX
Ozone-season
NOX
2%
........................
........................
2%
5%
3%
2%
2%
6%
........................
2%
2%
2%
........................
2%
4%
2%
2%
8%
2%
2%
2%
2%
5%
4%
7%
5%
2%
........................
........................
2%
8%
3%
2%
2%
4%
........................
2%
2%
2%
........................
3%
7%
2%
3%
6%
2%
2%
2%
2%
3%
5%
5%
6%
2%
2%
2%
2%
8%
3%
........................
........................
4%
3%
2%
........................
........................
2%
........................
........................
2%
3%
6%
2%
2%
2%
2%
3%
5%
5%
........................
for second round allocations and by
November 15 a second NODA of the list
of eligible units and their second round
allocations, which will also be recorded
in the allowance accounts by that date.
The comparable deadlines for the SO2
and NOX annual programs are December
15 and February 15. EPA believes that
these deadlines will provide sufficient
time for EPA to identify the units and
obtain their needed emissions data and
to calculate the allocations and
promulgate the notices.
d. Addition of Allowances to New Unit
Set-Asides
As discussed elsewhere in this
preamble, EPA proposed that, if a unit
with an existing-unit allocation does not
operate for 3 consecutive years, the
allowances that would otherwise have
been allocated to that unit, starting in
the seventh year after the first year of
non-operation, would be allocated to the
new unit set-aside for the state in which
the retired unit is located. EPA is
retaining this provision in the final rule
but is changing the time of nonoperation to 2 years and the time of
allowance allocation to a non-operating
unit to 4 years. Starting in the fifth year
of non-operation, allowances will be
allocated to the new unit set-aside for
the state in which the non-operating
unit is located.
EPA received comments that the new
unit set-asides were not sufficient to
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encourage the operation of new units.
One commenter suggested that
allowance allocations should cease after
3 years of non-operation because the
financial incentive gained from
receiving allowances beyond the 3-year
period is insignificant relative to
operating and fuel costs. Another
commenter said that providing
allowances to non-operating units is
unnecessary and distorts the market.
In addition to increasing the size of
the new unit set-aside in this final rule,
as described above, EPA is terminating
existing unit allocations starting in the
fifth year after the unit does not operate
for 2 consecutive years and reallocating
to the new unit set-aside the allowances
that the unit otherwise would have
received for the fifth and subsequent
years in order to make them available
for new units in the state. This approach
allows the new unit set-asides to grow
over time.
e. Allocations to New Units Locating in
Indian Country
EPA received several comments on
the proposed rule that it did not
explicitly address the distribution of
allowances to potential new units built
in Indian country. EPA recognized this
concern and requested comment on this
topic in the January 7, 2011 NODA.
In the final rule, EPA is providing a
mechanism to make allowances
available in the future for new units
built in Indian country. The final rule
establishes an Indian country new unit
set-aside for each pollutant in each state
whose borders encompass Indian
country (i.e., Florida, Iowa, Kansas,
Louisiana, Michigan, Minnesota,
Mississippi, Nebraska, New York, North
Carolina, South Carolina, Texas, and
Wisconsin). EPA will retain
administration of these Indian country
new unit set-asides as part of the
Transport Rule trading programs
whether or not a Transport Rule state
elects to modify or replace the Transport
Rule FIPs through approved SIP
revisions. EPA does not create Indian
country new unit set-asides for states
lacking Indian country within their
borders.
EPA determined the size of each
Indian country new unit set-aside by
calculating the ratio of square mileage of
Indian country to the square mileage of
the state within whose borders Indian
country is located. This calculation
yielded a maximum percentage of 5
percent when assessing all of the states
encompassing Indian country subject to
the final Transport Rule; this is referred
to as the ‘‘5 percent Indian country
factor’’ below. To determine the
maximum percentage, EPA used the
American Indian Reservations/Federally
Recognized Tribal Entities dataset,
which contains data for the 562
federally recognized tribal entities in the
contiguous U.S. and Alaska. EPA
accessed the data to analyze the
Transport Rule region and compare the
square miles of Indian country with the
square miles of the Transport Rule state
that includes the Indian country. EPA
then took the highest percentage as the
number to be applied across all states
with Indian country to determine the
size of the Indian country new unit setaside pertinent to that state’s budgets
under the Transport Rule. EPA chose to
use the maximum percentage (5 percent)
48293
from the Indian country analysis to
determine the Indian country set-aside
for each state on the basis that this
approach would reserve a reasonable
number of allowances from each state’s
budget for potential allocation to new
units that may locate in Indian country
within that state’s borders. Any
allowances from the Indian country new
unit set-aside that are not allocated in a
given control period are redistributed
into the state’s new unit set-aside. As
discussed above, any allowances not
allocated from that new unit set-aside
are redistributed to existing units based
on the existing units’ share of the total
existing unit allocations.
To calculate the size of each tribal
new unit set-aside, EPA applied this 5
percent Indian country factor to the
portion of the state’s new unit set-aside
originally determined by accounting for
‘‘potential’’ new units, which as
described above was set at 2 percent of
each pollutant’s budget in each state.
Therefore, the Indian country new unit
set-aside is 5 percent of 2 percent of a
state’s budget, or 0.1 percent of that total
state budget. EPA did not apply the 5
percent Indian country factor to the
state-specific planned unit portion of
each state’s new unit set-aside because
the planned unit portion is determined
using projected emissions from specific,
known units coming online after
January 1, 2010, and none of these
known units are located in Indian
country.
The Indian country new unit setasides in the following Transport Rule
states with Indian Country are shown in
Table VII.D.2–2.
TABLE VII.D.2–2—NEW UNIT SET-ASIDE ALLOWANCES FOR INDIAN COUNTRY
[Tons]
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SO2
2012–
2013
Florida ..............................................................................................................................
Iowa ..................................................................................................................................
Kansas .............................................................................................................................
Louisiana ..........................................................................................................................
Michigan ...........................................................................................................................
Minnesota .........................................................................................................................
Mississippi ........................................................................................................................
Nebraska ..........................................................................................................................
New York .........................................................................................................................
North Carolina ..................................................................................................................
South Carolina .................................................................................................................
Texas ...............................................................................................................................
Wisconsin .........................................................................................................................
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SO2
2014
and
beyond
Annual
NOX
2012–
2013
Annual
NOX
2014
and
beyond
Ozoneseason
NOX
2012–
2013
Ozoneseason
NOX
2014
and
beyond
............
107
42
............
229
42
............
65
27
137
89
244
80
............
75
42
............
144
42
............
65
19
58
89
244
40
............
38
31
............
60
30
............
26
18
51
32
134
32
............
38
26
............
58
30
............
26
18
42
32
134
30
28
............
............
13
............
............
10
............
8
22
14
63
............
28
............
............
13
............
............
10
............
8
18
14
63
............
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Under the FIPs, EPA allocates
allowances from Indian country new
unit set-asides in essentially the same
manner as it allocates allowances from
state new unit set-asides. The approach
for identifying, and determining the
number of allowances allocated to, new
units in Indian country is the same as
the approach for identifying and
determining allocations for non-Indian
country new units covered by the state
new unit set-aside, and allocations are
made in two rounds using the same
schedules for promulgation of notices of
data availability. However, as discussed
above, unallocated allowances in the
Indian country set-asides are handled
differently from unallocated allowances
in the state new unit set-asides in that
unallocated Indian country new unit
set-aside allowances are first transferred
back into the state new unit set-aside
and then, if still not allocated to new
units, are distributed to existing units in
the state. EPA believes that the abovedescribed approach in establishing and
handling the Indian country new unit
set-asides and state new unit set-asides
is a reasonable way of making a
sufficient amount of allowances
available for new units in the state and
Indian country located in the state and
ensuring that the entire state budget is
available to either new or existing units
in the state and Indian country. EPA
retains administration of these Indian
country new unit set-asides (and, of
course, the portions of state budgets that
comprise these set-asides) as part of the
Transport Rule trading programs even if
a state elects to modify or replace the
Transport Rule FIPs through approved
SIP revisions. EPA continues to manage
and distribute the Indian country new
unit set-aside allowances in the same
manner as under the FIPs. Unallocated
allowances in the Indian country new
unit set-aside will be returned to the
portion of the state budget allocated
under the approved SIP’s allocation
provisions. EPA believes that this
approach is reasonable because EPA,
rather than the states, has the authority
and responsibility of administering the
Transport Rule with regard to new units
that locate in Indian country.
E. Assurance Provisions
To ensure that the FIPs require the
elimination of all emissions that EPA
has identified that significantly
contribute to nonattainment or interfere
with maintenance within each
individual state, the Agency is adopting
assurance provisions in addition to the
requirement that sources hold
allowances sufficient to cover their
emissions. These assurance provisions
limit emissions from each state to an
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amount equal to that state’s trading
budget plus the variability limit for that
state (i.e., the state assurance level). As
discussed in section VI of this preamble,
this variability limit takes into account
the inherent variability in baseline EGU
emissions and recognizes that state
emissions may vary somewhat after all
significant contribution to
nonattainment and interference with
maintenance are eliminated. This
approach also provides sources with
flexibility to manage growth and electric
reliability requirements, thereby
ensuring the country’s electric demand
will be met, while meeting the statutory
requirement of eliminating significant
contribution to nonattainment and
interference with maintenance.
Starting in 2012, EPA is establishing,
as part of the FIPs, limits on the total
emissions that may be emitted from
EGUs at sources in each state. For any
single year, the state’s emissions must
not exceed the state budget with the
variability limit allowed for any single
year for that state (i.e., the state’s 1-year
variability limit). In other words, in
addition to covered sources being
required to hold allowances sufficient to
cover their emissions, the total sum of
EGU emissions in a particular state
cannot exceed the state budget with the
state’s 1-year variability limit in any 1
year (i.e., the state’s assurance level).
EPA is not finalizing 3-year variability
limits that were included in the
proposal for the reasons explained
previously in section VI.E of this
preamble. The state budgets, variability
limits, and state assurance levels for
each state are shown in Tables VI.F–1,
VI.F–2 and VI.F–3 in section VI.F of this
preamble. The basis for the variability
limits is also described in section VI.E
of this preamble. Additional details may
be found in the Power Sector Variability
Final Rule TSD in the docket to this
rule.
To implement this requirement, EPA
first evaluates whether any state’s total
EGU emissions in a control period
exceeded the state’s assurance level. If
any state’s EGU emissions in a control
period exceed the state assurance level,
then EPA applies additional criteria to
determine which owners and operators
of units in the state will be subject to an
allowance surrender requirement. In
applying the additional criteria, EPA
evaluates which groups of units at the
common designated representative (DR)
level had emissions exceeding the
respective common DR’s share of the
state assurance level (regardless of
whether the source had enough
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allowances to cover its emissions)
during the control period.82
The requirement that owners and
operators surrender allowances under
the assurance provisions will be
triggered only if two criteria are met: (1)
The group of sources and units with a
common DR are located in a state where
the total state EGU emissions for a
control period exceed the state
assurance level; and (2) that group with
the common DR had emissions
exceeding the respective DR’s share of
the state assurance level. The share of
the assurance penalty borne by the
owners and operators will be based on
the amount by which the total emissions
for the units in the group exceed the
common DR’s share of the state
assurance level as a percentage of the
total calculated for all such groups of
sources and units in the state. Thus, the
owners and operators of each such
group of sources and units must
surrender an amount of allowances
equal to the excess of state EGU
emissions over the state assurance level
multiplied by the owners’ and
operators’ percentage and multiplied by
two (to reflect the penalty of two
allowances for each ton of the state’s
excess EGU emissions). See Table VII.E–
1 below for an illustrative example.
This approach in the final rule of
implementing the assurance provisions
on a common designated representative
basis contrasts with the approach in the
proposed rule of implementing the
assurance provisions on an owner basis.
In the January 7, 2011 NODA, EPA
requested comment on the alternative of
basing the assurance provision penalty
using common designated
representatives, and some commenters
supported this alternative. The common
designated representative approach is
simpler and avoids the need to collect
information on percentage ownership
(which information is not used in any
other provisions of the Transport Rule
trading programs).
In addition, the common designated
representative approach provides
additional flexibility to owners and
operators who have only one or a few
units in a given state but have the
option of selecting a common
designated representative with owners
and operators of other units in the state.
EPA expects companies in various states
will readily be able to manage their
82 A group of one or more sources and units in
a state has a common designated representative
where the same individual is authorized as the
designated representative (not the alternate
designated representative) for that group of sources
and units as of April 1 immediately following the
allowance transfer deadline for the control period
involved.
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emissions to stay collectively below
their state’s assurance levels as they
track emissions quarterly throughout the
year and manage their generation units
and pollution control efforts
accordingly. However, if the state
appears to be approaching its assurance
level, this final rule also gives
companies the ability to further ensure
that they will not have excess emissions
by combining multiple units under a
common DR. This flexibility allows
utilities to re-balance allowances and
emissions to mitigate penalty risk if the
state violates its assurance level. In a
state that does not appear to risk
violating its assurance level in a given
period, utilities would not need to
consider the assurance aspect of
selecting DRs. However, EPA anticipates
that in the event utilities desire
additional certainty or mitigation of
assurance penalty risk, they will take
advantage of this common DR provision
or pursue similar private arrangements
with each other to cover their emissions
at the lowest possible cost.
While the DR provision could benefit
utilities by allowing them to pool their
penalty risk, the utilities would still be
subject to the antitrust laws. As with
any joint venture between competitors,
the efficiency benefits of pooling risk
would be weighed against any
anticompetitive harm associated with
DRs.
This new feature in the final rule, in
conjunction with the simplifications to
the final rule’s variability limits
described in section VI.E, will give
companies under the air quality-assured
trading program greater flexibility in
each state to determine the most costeffective pattern of emission reductions
while EPA ensures each state meets its
assurance level needed to address the
significant contribution in each state.
In the January 7, 2011 NODA, EPA
also requested comment on continuing
to link allocations to assurance
provision allowance surrender
requirements. Even though the final rule
uses a different allowance allocation
methodology than the allocation
methodology that was proposed, the
final rule continues to treat the groups
of units with greater emissions than
their allocations plus share of state
variability as responsible for the state’s
excess of emissions over the state
assurance level. EPA believes that this
approach is reasonable because any
state that exceeds its state assurance
level likely does so because not all units
have made the reductions necessary to
eliminate the state’s contribution to
nonattainment or interference with
maintenance. Moreover, the groups of
units with emissions exceeding their
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allocations plus share of variability are
the units most likely to have contributed
to the state’s exceedance of its state
assurance level and thus to the state’s
triggering of the assurance provisions.
Consequently, EPA concludes that it is
reasonable to penalize owners and
operators of those sources and units
(grouped by common DR) for the state’s
exceedance through application of the
assurance provision allowance
surrender requirement. Some
commenters stated that this is a
reasonable approach.
While a few commenters suggested
alternative approaches to the assurance
provisions, EPA believes that the
suggested alternatives are not workable
and are likely to create implementation
problems. These commenters suggested
variations of approaches that would
have created state-specific and vintage
year-specific allowances that would
have been traded independently of
compliance allowances. These
differentiated allowances would have
fragmented the allowance markets and
made the programs resemble the
intrastate trading option that EPA
rejected because of market power and
other concerns described in the
proposal.
The existence of the assurance
provisions with significant penalties
imposed if a state’s emissions exceed
the state budget with the variability
limit, along with other features of the
Transport Rule trading programs
discussed below, will ensure that state
emissions stay below the level of the
budget with the variability limit. In
making compliance decisions and
determining to what extent to rely on
purchased or banked allowances,
owners and operators will have to take
into account the risk of triggering the
assurance provisions in the state
involved and of incurring significant
assurance provision penalties. The
greater the extent to which units sharing
a common DR have emissions exceeding
the DR units’ allocations plus share of
the state variability limit, the greater the
risk of being subject to the assurance
provision penalties.
As discussed previously in section
VII.D.2, EPA allocates allowances to a
new unit for the control period during
which the unit commences commercial
operation from the new unit set-aside
based on its emissions. In the case
where assurance provisions for a state
are triggered in the year that a new unit
commences operation, the unit’s share
of the state assurance level is calculated
using the unit’s allocation from the new
unit set-aside plus its proportional share
of the variability limit. There is the
possibility that a new unit would
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48295
receive no allocation for the control
period during which the unit
commences commercial operation. EPA
sees no reasonable basis for
disadvantaging owners and operators
because they started up a new unit and
EPA had no emissions data on which to
base an allocation from the new unit setaside or no allowances were available
for the unit in the state’s new unit setaside.83 For these new units, EPA would
use a specific surrogate number to
calculate the maximum amount of
emissions that the unit would likely
have had during that year. The surrogate
emission number applies only if the
state’s assurance provisions are
triggered and only in the first year of the
new unit’s commercial operation for a
new unit that did not receive an
allocation from the set-aside. The
methodology for calculating the
surrogate emission number is essentially
unchanged from the proposal (75 FR
45313). For more details on capacity
factors for new units, see ‘‘Capacity
Factors Analysis for New Units Final
Rule TSD.’’
These assurance provisions are above
and beyond the fundamental
requirement for each source to hold
enough allowances to cover its
emissions in the control period. Failure
to hold enough allowances to cover
emissions is a violation of the CAA,
subject to an automatic penalty and
discretionary civil penalties, as
described in section VII.F of this
preamble.
Several features of the air qualityassured trading programs work in
conjunction with the assurance
provisions to ensure state emissions do
not exceed state assurance levels. The
air quality-assured trading programs
have: State-specific budgets that do not
include the variability limits and that
are the basis for allocating allowances in
each state so that total allocations in a
state cannot exceed the state budget; a
requirement that owners and operators
of each source hold enough allowances
to cover source emissions for each
control period; assurance provisions
that require owners and operators to
hold a significant amount of additional
allowances in a state if the assurance
provisions are triggered; and additional
penalties for failing to hold sufficient
allowances under the assurance
provisions. The underlying mechanism
of cap and trade—with a cap on
allowances issued and a requirement to
83 Some other units (e.g., those units with no data
for the 2006–2010 base period) may have a zero
allocation for a control period. However, those are
highly likely to be units that will continue to
operate rarely or not at all and so will incur little
or none of the assurance provision penalties.
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hold allowances covering emissions—
has succeeded, even without assurance
provisions, in broadly reducing
emissions below allowance allocation
levels. The accumulated data, history,
and experience from cap and trade
programs underscore that emission
reduction requirements and
environmental and public health goals
of the programs have been met and, in
many instances, exceeded. Additionally,
EPA has now added assurance
provisions to ensure that emissions
within a state do not exceed the state
budget with the variability limitation
that eliminates the state’s significant
contribution to nonattainment and
interference with maintenance in
downwind states.
Emissions from a common DR’s group
of units in excess of the DR’s share of
the state budget with the variability
limit are not a violation of the rule or
the CAA, but do lead to strict allowance
surrender requirements. Specifically,
the owners and operators with a
common DR will be required to
surrender two allowances for each ton
of their proportional share of the
exceedance of the state budget with the
variability limit. Failing to hold
sufficient allowances to meet the
allowance surrender requirement will
be a violation of the regulations and the
CAA and subject to discretionary civil
penalties under CAA section 113.
Allowances surrendered to meet an
assurance provision penalty may be
from the year immediately following the
control period in which the state
assurance level was exceeded (i.e., the
year during which the penalty is
assessed) or any prior year. Any future
vintage allowances beyond the year in
which the penalty is assessed may not
be used to meet an assurance provision
penalty.
This penalty level is a change from
the proposal, in which one allowance
was to be surrendered for each ton of
emissions over the state assurance level.
EPA ran an IPM modeling scenario in
order to assess the level of penalty that
would be sufficient to deter sources
from exceeding state assurance levels.
According to the model, no state would
exceed its assurance level and incur the
two-for-one allowance penalty in either
2012 or 2014, although some states emit
up to the assurance level. The two-forone allowance surrender requirement is
significant, and EPA believes that this
penalty—along with the other elements
of the Transport Rule discussed above—
will be sufficient to ensure that the state
emissions will not exceed the budgets
plus the variability limits. See the
Assurance Penalty Level Analysis Final
Rule TSD for further details of the
analysis.
Below are examples of how the
penalty will be assessed for four
common designated representatives in
the same state if the assurance
provisions are triggered. In the first case,
DR1’s combined units were allowed to
emit up to 71 tons of SO2 (60 * 118
percent), but actually emitted 75 tons
during the control period, or 4 more
than their share of the state assurance
level. Since the state, as a whole
exceeded the state assurance level by 15
tons, DR1’s share of the penalty is 25
percent of the total penalty, or 8
allowances (25 percent of 30).
FIGURE VII.E–1—ASSURANCE PROVISION ALLOWANCE SURRENDER EXAMPLE
Allowances
allocated
DR1
DR2
DR3
DR4
Allocation +
share of
variability
Emissions
above
allocation
Total
emissions
Emissions
above allocation + share of
variability
Share of state
exceedance
(%)
Penalty
(allowances
surrendered)
..............................
..............................
..............................
..............................
60
20
10
10
71
24
12
12
75
33
15
10
15
13
5
0
4
9
3
¥2
25%
56%
19%
0%
8
17
6
¥
Total .............................
100
118
133
33
15
100%
30
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DR1, DR2, DR3, and DR4 are all in the same state.
State budget plus 18 percent variability limit is 118 tons (100 + 18 = 118).
State exceeded its assurance level by 15 tons (133¥118 = 15).
Penalty is 2 allowances per ton over the assurance level (2 × 15 = 30).
Some numbers may not add up due to rounding.
In the proposal, EPA took comment
on whether assurance provisions should
be implemented starting in 2012 or
2014. While a number of commenters
supported the proposal to start in 2014,
EPA received several comments making
the case that starting assurance
provisions in 2012 would be more
compatible with the Court’s opinion in
North Carolina, which emphasized
EPA’s obligation to require elimination
of emissions within the states that
significantly contribute to
nonattainment or interfere with
maintenance. In this final rule, EPA
makes the assurance provisions effective
starting in 2012 because this approach
provides even further assurance,
consistent with North Carolina, that
each state’s prohibited emissions will be
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eliminated from the start of the
Transport Rule trading programs.
F. Penalties
Under the final Transport Rule FIPs
(like under the proposed rule), the
owners and operators of each covered
source must hold, as of the allowance
transfer deadline, an allowance for each
ton of SO2 or NOX emitted by the source
and are subject to penalties if they fail
to comply with this allowance-holding
requirement.
In particular, the owners and
operators must hold in the source’s
compliance account in the Allowance
Management System enough allowances
issued for the respective Transport Rule
annual trading program (SO2 Group 1,
SO2 Group 2, or annual NOX program)
to cover the annual emissions of the
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relevant pollutant from all covered units
at the source. The allowances must have
been issued for the year in which the
emissions occurred or a prior year. If the
owners and operators fail to meet this
allowance-holding requirement, they
must provide—for deduction by the
Administrator from the source’s
compliance account—one allowance as
an offset, and one allowance as an
excess emissions penalty, for each ton of
emissions (i.e., excess emissions) in
excess of the amount of allowances
held. The allowances surrendered for
the excess emissions penalty must be
allocated for the control period in the
year immediately following the year
when the excess emissions occurred or
for a control period in any prior year.
The offset and the excess emissions
penalty are automatic requirements in
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that they must be met without any
further action by EPA (e.g., any
additional proceedings) regardless of the
reason for the occurrence of the excess
emissions. In addition, each ton of
excess emissions, as well as each day in
the averaging period (i.e., the control
period of one calendar year), constitute
a violation of the CAA, and the
maximum discretionary civil penalty is
$25,000 (inflation-adjusted to $37,500
for 2010) per violation under CAA
section 113. This means that, if a source
has emissions in excess of allowances
held for the source as of the allowance
transfer deadline for a control period,
the number of tons of excess emissions
multiplied by the total number of days
in that control period and multiplied by
$25,000 (inflation adjusted) equals the
maximum discretionary civil penalty for
that occurrence of excess emissions.
For the ozone-season NOX trading
program, the same provisions apply as
for an annual program, except that the
averaging period (i.e., the control
period) is the ozone season, not a
calendar year. Consequently, the
relevant emissions are for an ozone
season, the allowances usable to meet
the allowance-holding requirement are
allowances issued for Transport Rule
ozone-season NOX trading program for
the ozone season involved or a prior
ozone season, and the number of days
used in calculating the maximum civil
penalty is the number in the ozone
season.
Commenters expressed concern that
the proposed FIPs expressly stated that,
for purposes of determining the
maximum discretionary civil penalty for
failure to meet the allowance-holding
requirement, each ton of emissions
lacking a held allowance would be a
violation and each day in the averaging
period involved would be a violation.
Some commenters compared the
proposed penalty provisions for excess
emissions with the excess emissions
penalty provisions under the Acid Rain
Program and claimed that the proposed
penalty provisions differed from the
Acid Rain Program provisions and were
excessive.
In fact, however, the final FIP
provisions concerning discretionary
civil penalties are essentially the same
as those under the Acid Rain Program,
as well as those under the NOX Budget
Trading Program and the CAIR trading
programs. In particular, the Acid Rain
Program regulations state that each ton
of SO2 excess emissions constitutes ‘‘a
separate violation’’ of the CAA. 40 CFR
72.9(c)(2). Moreover, while the Acid
Rain Program regulations do not
expressly address that each day in the
averaging period (i.e., a calendar year
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control period under the Acid Rain
Program) constitutes a separate violation
when a unit has excess emissions for the
calendar year, the courts have addressed
this question. In decisions applying the
discretionary civil penalty provisions in
section 309(d) of the Clean Water Act,
which are analogous to the civil penalty
provisions in CAA section 113, the
courts have interpreted the provisions to
mean that, when a source violates the
emission limitation for a multi-day
control period, the source has a
violation for each day in the control
period, as well as for each ton of excess
emissions on each such day. See, e.g.,
Chesapeake Bay Foun. v. Gwaltney of
Smithfield, 791 F.2d 304, 313–15 (4th
Cir. 1986), Atlantic States Legal Foun. v.
Tyson Foods, 897 F.2d 1128, 1139–40
(11th Cir. 1990), and U.S. v. Allegheny
Ludlum Corp., 366 F.3d 164, 169 (3d.
Cir. 2004). As noted by the courts, the
treatment of each ton and each day as
a separate violation is used for purposes
of setting the maximum discretionary
civil penalty. Because CAA section 113
sets the maximum civil penalty, EPA, of
course, has the discretion to tailor the
penalty amount that it seeks in any
specific occurrence of excess emissions
to reflect the circumstances of that
excess emission occurrence. See 42
U.S.C. 7413(b) (stating that the
Administrator may commence a civil
action ‘‘to assess and recover a civil
penalty of not more than $25,000 per
day for each violation’’). Moreover,
when a district court imposes a civil
penalty, the court ‘‘retains discretion to
assess a penalty much smaller than the
maximum, as the situation requires.’’
Chesapeake Bay, 791 F.2d at 316. In
addition, the Acid Rain Program
regulations state that any allowance
deduction, excess emission penalty, or
interest under the Acid Rain Program
regulations ‘‘shall not affect liability’’ of
the owners and operators ‘‘for any
additional fine, penalty, or assessment,
or their obligation to comply with any
other remedy, for the same violation, as
ordered under the [CAA],’’ including
under CAA section 113 providing for
discretionary civil penalties. 40 CFR
77.1(b). In summary, under the Acid
Rain Program, each ton of excess
emissions and each day in the averaging
period (i.e., the calendar year) constitute
a violation, the resulting number of
violations times $2,000 is the maximum
civil penalty for violating owners and
operators, and EPA has the discretion to
impose a civil penalty at or below such
maximum, in addition to the automatic
requirement to surrender one allowance
and pay $2,000 (inflation adjusted) for
each ton of excess emissions.
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The final FIPs take an analogous
approach to that under the Acid Rain
Program. Specifically, the final FIPs
state both that each ton of excess
emissions is a violation of the CAA and
that each day in the averaging period
(i.e., a calendar year under the annual
programs and the ozone season under
the ozone-season program) is a
violation. Moreover, the imposition of
civil penalties at or below the maximum
amount resulting from the maximum
penalty calculation is in addition to the
automatic allowance surrender and
penalty totaling 2 allowances per ton of
excess emissions. Thus, commenters’
assertion that the approach in the final
FIPs is inconsistent with the approach
in the Acid Rain Program is incorrect.
Moreover, EPA has taken this same
general approach in two other trading
programs (i.e., the NOX Budget Trading
Program and the CAIR trading
programs), whose regulations explicitly
state that each ton and each day of the
averaging period constitute a violation.
See 40 CFR 96.54(d)(3) (NOX Budget
Trading Program); and 40 CFR 96.106(d)
(CAIR).
In any event, EPA maintains that the
approach of treating each excess
emission ton and each day in the
averaging period as a violation for
purposes of calculating the maximum
discretionary civil penalty is reasonable.
Some commenters suggested that only
the days on which a source’s cumulative
control period emissions exceed the
amount of allowances that the source
then holds for that control period
should be treated as a violation.
However, this suggested approach
makes little sense in the context of the
Transport Rule trading programs.
In order to provide owners and
operators compliance flexibility, the
Transport Rule trading programs do not
require source owners and operators to
hold any amount of allowances to cover
emissions until the allowance transfer
deadline, no matter what the source’s
cumulative control period emissions are
before that deadline. The commenters’
approach of comparing—each day,
cumulative emissions and allowances
held—for purposes of calculating
maximum civil penalties would be
inconsistent with the flexibility that
EPA intends to provide owners and
operators. For example, under the
commenters’ suggested approach,
owners and operators that buy or sell
allowances in the allowance market or
hold allowances in a company-wide
account, do not transfer allowances into
their source’s compliance account until
just before the allowance transfer
deadline, and end up with some excess
emissions for the calendar year would
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face a significantly higher maximum
civil penalty than owners and operators
that every day increase the amount of
allowances held in their source’s
compliance account as the source’s
cumulative emissions increase and end
up with the same amount of excess
emissions for the calendar year. In short,
the commenters’ approach would
penalize owners and operators that use
some of the compliance flexibility that
the trading programs are intended to
provide.
EPA also maintains that it is
reasonable to both impose the automatic
allowance surrender and penalty
provisions and to retain the discretion
to impose civil penalties for the same
occurrence of excess emissions. This
approach encourages compliance with
the allowance-holding requirement by
ensuring that violating owners and
operators are penalized automatically
(i.e., without any further administrative
or judicial proceedings, except for
appeals) and that EPA can seek
additional penalties where the
circumstances warrant discretionary
civil penalties. In fact, the Acid Rain
Program, for which CAA Title IV
mandated this approach, has achieved a
very high level of compliance with the
requirement to hold allowances
covering SO2 emissions and therefore
resulted in major reductions in utility
SO2 emissions. See 42 U.S.C.7651j(a).
Similarly, the NOX Budget Trading
Program and CAIR trading programs,
which took the same approach, also
have achieved very high compliance
levels and major utility emission
reductions.
EPA notes that, in calculating
maximum civil penalties when owners
and operators fail to hold allowances
required under the assurance provisions
in the final FIPs, EPA takes a similar
approach in determining the number of
violations. Each ton for which an
allowance is not held as required and
each day in the control period involved
constitute a violation of the CAA. As
discussed elsewhere in this preamble,
EPA believes that this calculation
approach is also reasonable in the
context of the assurance provisions and
that taking an approach like the
commenters’ suggested approach
described above would be inconsistent
with some of the flexibility that the
Transport Rule trading programs are
intended to provide.
G. Allowance Management System
The final Transport Rule trading
programs, like the proposed preferred
remedy, utilize EPA’s allowance
management system (AMS), which
currently supports allowance surrender,
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transfer, and tracking activity under the
Acid Rain Program and CAIR. EPA
received no adverse comment on this
aspect of the proposed rule.
The primary role of AMS is to provide
an efficient, automated means for
covered sources to comply and for EPA
to determine whether covered sources
are complying, with the emissionsrelated provisions of the Transport Rule
trading programs. As was proposed,
each of the final SO2 trading programs
and final NOX trading programs is
separately handled in the AMS, which
is used to track Transport Rule trading
program SO2 and NOX allowances held
by covered sources, as well as such
allowances held by other entities or
individuals.
In addition, the AMS tracks: The
allocation of all SO2 and NOX
allowances; holdings of SO2 and NOX
allowances in compliance accounts (i.e.,
accounts for individual covered
sources), general accounts (i.e., accounts
for other entities such as companies and
brokers), and assurance accounts (i.e.,
accounts for allowance surrender by
owners and operators of groups of
sources and units with common
designated representatives under the
assurance provisions); deduction of SO2
and NOX allowances for compliance
purposes (including deductions from
assurance accounts where necessary);
and transfers of allowances between
accounts. The AMS also allows the
public to see whether each source is in
compliance and provides information to
the allowance market and the public in
general, including information on
ownership of allowances, dates of
allowance transfers, buyer and seller
information, and the serial numbers of
allowances transferred.
H. Emissions Monitoring and Reporting
Under the proposed rule, units subject
to the Transport Rule trading programs
would monitor and report NOX and SO2
mass emissions in accordance with 40
CFR part 75, as incorporated in the
proposed rule, and with certain other
specified requirements, such as
compliance deadlines.
In the final rule, like the proposed
rule, covered units must comply with
emissions monitoring and reporting
requirements that are largely
incorporated from Part 75 monitoring
and reporting requirements.
Under the final rule and under Part
75, a unit has several options for
monitoring and reporting, namely the
use of: a CEMS; an excepted monitoring
methodology (NOX mass monitoring for
certain peaking units and SO2 mass
monitoring for certain oil- and gas-fired
units); low mass emissions monitoring
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for certain non-coal-fired, low emitting
units; or an alternative monitoring
system approved by the Administrator
through a petition process. In addition,
the Administrator can approve petitions
for alternatives to Transport Rule and
Part 75 monitoring, recordkeeping, and
reporting requirements.
Further, the final rule and Part 75
specify that each CEMS must undergo
rigorous initial certification testing and
periodic quality assurance testing
thereafter, including the use of relative
accuracy test audits (RATAs) and 24hour calibrations. In addition, when a
monitoring system is not operating
properly, standard substitute data
procedures are applied and result in a
conservative estimate of emissions for
the period involved.
In addition, the final rule and Part 75
require electronic submission, to the
Administrator and in a format
prescribed by the Administrator, of a
quarterly emissions report. The report
must contain all of the data required
concerning NOX annual and ozoneseason and SO2 annual emissions.
Most Transport Rule units are in
states subject to CAIR and are already
monitoring and reporting NOX and/or
SO2 under CAIR and the Acid Rain
Program, which programs also use Part
75 monitoring and reporting. Units
under the Transport Rule annual trading
programs and in states subject to CAIR
generally have no changes to their
monitoring and reporting requirements.
These units must continue to monitor
and submit reports on a year-round
basis as they have under CAIR.
Therefore, units in the following states
must monitor and report both SO2 and
NOX year-round under the Transport
Rule: Alabama, Georgia, Illinois,
Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota,
Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio,
Pennsylvania, South Carolina,
Tennessee, Texas, Virginia, West
Virginia and Wisconsin.
Some states (Kansas, Minnesota, and
Nebraska) subject to the Transport Rule
annual trading programs were not
subject to CAIR. Transport Rule units in
those states must meet monitoring and
reporting requirements that are new
except to the extent the units were
subject to Part 75 under some other
program (such as the Acid Rain
Program).
Further, some states (Florida,
Louisiana, and Mississippi) subject to
the Transport Rule ozone-season trading
program but not the Transport Rule
annual trading programs were subject to
the annual and ozone-season trading
programs under CAIR. Transport Rule
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units in those states must continue to
monitor and report in accordance with
Part 75 but have the option of
monitoring and reporting on a yearround or ozone-season-only basis.
In addition, one state (Arkansas)
subject to the Transport Rule ozoneseason trading program but not to the
Transport Rule annual trading program
was similarly subject to only the ozoneseason trading program in CAIR.
Transport Rule units in that state
continue to have the option of
monitoring and reporting NOX on a
year-round or ozone-season-only basis.
Finally, some states (Connecticut,
Delaware, District of Columbia, and
Massachusetts) that were subject to
CAIR are not subject to the Transport
Rule. Electric generating units in those
states must continue to meet monitoring
and reporting requirements only to the
extent the units are subject to Part 75
under some other program (such as the
Acid Rain Program or a state adopted
program requiring such monitoring and
reporting).
EPA is finalizing requirements for
existing Transport Rule units in states
covered by the Transport Rule annual
trading programs to monitor and report
SO2 and NOX emissions by January 1,
2012 programs and for existing
Transport Rule units in states covered
by the Transport Rule ozone-season
trading program to monitor NOX
emissions by May 1, 2012. The use of
Part 75 certified monitoring
methodologies is required in both cases.
As discussed previously, most covered
existing units will generally have no
changes to their monitoring and
reporting requirements and will
continue to monitor and submit reports
under Part 75 as they have under CAIR.
Existing units that have not been subject
to Part 75 monitoring and reporting
requirements in the past have less than
1 year to install, certify, and operate the
required monitoring systems. EPA
believes that these units will be able to
comply with this requirement because
the monitoring equipment needed is not
extensive or is largely in place already
for the purpose of meeting other
requirements. Quality assurance and
reporting provisions and data system
upgrades may be necessary, but EPA
believes that there is sufficient time to
accomplish this by the deadline for
existing units in the final rule.
In the proposed rule, the compliance
deadline for installing, certifying, and
operating the required monitoring
systems at new units was based upon
the date of commencement of
commercial operation. A new unit
would have to install and certify its
monitoring system within 180 days of
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the commencement of commercial
operation. The final rule adopts this
deadline, which is consistent with the
approach recently adopted in Part 75
under the Acid Rain Program. See 76 FR
17288, 17289 (March 28, 2011).
Using this deadline (rather than a
deadline, used previously in Part 75, of
the earlier of the unit’s 90th operating
day or 180 days after the unit’s
commencement of commercial
operation) ensures that new units have
sufficient time to complete installation
and certification of monitoring systems
and facilitates units’ compliance.
Because of unit shakedown problems,
some new units have had difficulty
meeting a deadline earlier than 180 days
after commencement of commercial
operation. Further, using this deadline
facilitates owners’ and operators, and
EPA’s, ability to track important dates
related to monitoring, reporting, and
allowance holding. Under the final rule,
the requirement that a unit hold enough
allowances to cover its emissions starts
on the later of the commencement of the
Transport Rule trading program
involved or the deadline for installation
and certification of the monitoring
system. Having a simple, easily
determined deadline (180 days after the
commencement of commercial
operation) makes it easier for owners
and operators and EPA to determine
when allowance-holding requirements
begin, as well as when monitoring and
reporting requirements begin. In
contrast, using a deadline involving
determination of a unit’s 90th operating
day required keeping track of any days
on which the unit did not operate (e.g.,
due to problems associated with
shakedown of the unit). EPA found that
owners and operators have had more
difficulty reporting the 90th operating
day than in reporting the
commencement of commercial
operation, and once the latter date is
reported, EPA can independently
determine the 180th calendar day after
the reported date.
I. Permitting
1. Title V Permitting
The final Transport Rule (like the
proposed rule) does not establish any
permitting requirements independent of
those under Title V of the CAA and the
regulations implementing Title V, 40
CFR Parts 70 and 71.84 All major
stationary sources of air pollution and
certain other sources are required to
apply for title V operating permits that
include emission limitations and other
84 Part 70 addresses requirements for state Title V
programs, and Part 71 governs the federal Title V
program.
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conditions as necessary to assure
compliance with applicable
requirements of the CAA, including the
requirements of the applicable State
Implementation Plan. CAA §§ 502(a)
and 504(a), 42 U.S.C. 7661a(a) and
7661c(a). The ‘‘applicable
requirements,’’ that must be addressed
in title V permits are defined in the Title
V regulations (40 CFR 70.2 and 71.2
(definition of ‘‘applicable
requirement’’)).
EPA anticipates that, given the nature
of the units covered by the final
Transport Rule, most of the sources at
which they are located are already or
will be subject to Title V permitting
requirements. For sources subject to
Title V, the requirements applicable to
them under the final FIPs will be
‘‘applicable requirements’’ under Title V
and therefore will need to be addressed
in the Title V permits. For example,
requirements under the final FIPs
concerning designated representatives,
monitoring, reporting, and
recordkeeping, the requirement to hold
allowances covering emissions, the
assurance provisions, and liability will
be ‘‘applicable requirements’’ to be
addressed in the permits.
The Title V permits program includes,
among other things, provisions for
permit applications, permit content, and
permit revisions that will address the
applicable requirements under the final
FIPs in a manner that will provide the
flexibility necessary to implement
market-based programs such as the
Transport Rule trading programs. For
example, the Title V regulations provide
that a permit issued under Title V must
include, for any ‘‘approved * * *
emissions trading and other similar
programs or processes’’ applicable to the
source, a provision stating that no
permit revision is required ‘‘for changes
that are provided for in the permit.’’ 40
CFR 70.6(a)(8) and 71.6(a)(8). Consistent
with this provision in the Title V
regulations, the Transport Rule trading
program regulations include a provision
stating that no permit revision is
necessary for the allocation, holding,
deduction, or transfer of allowances.
Consistent with the Title V regulations,
this provision will also be included in
each Title V permit for a covered source.
As a result, allowances can be traded (or
allocated, held, or deducted) under the
final FIPs without a revision of the Title
V permit of any of the sources involved.
As a further example of flexibility
under Title V, the Title V regulations
allow the use of the minor permit
modification procedures for permit
modifications ‘‘involving the use of
economic incentives, marketable
permits, emissions trading, and other
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similar approaches, to the extent that
such minor permit modification
procedures are explicitly provided for in
an applicable implementation plan or in
applicable requirements promulgated by
EPA.’’ 40 CFR 70.7(e)(2)(i)(B) and 40
CFR 71.7(e)(1)(i)(B). The final FIPs set
forth in detail, and reference relevant
provisions in Part 75 concerning, the
approaches that are available for
covered units to use for monitoring and
reporting emissions (i.e., approaches
using a continuous emission monitoring
system, an excepted monitoring system
under appendices D and E to Part 75, a
low mass emissions excepted
monitoring methodology under § 75.19,
or an alternative monitoring system
under subpart E of Part 75). The final
FIPs also require unit owners and
operators to submit monitoring system
certification applications (or, for
alternative monitoring systems,
petitions) to EPA establishing the
monitoring and reporting approach
actually to be used by the unit and
allow owners and operators to submit
petitions for alternatives to any specific
monitoring and reporting requirement.
These applications and petitions are
subject to EPA review and approval to
ensure consistency in monitoring and
reporting among all trading program
participants, and EPA’s responses to any
petitions for alternative monitoring
systems or for alternatives to specific
monitoring or reporting requirements
are to be posted on EPA’s Web site.
Moreover, EPA intends that each
covered unit’s Title V permit will
include a description of the general
approach that the covered unit is
required to use for monitoring and
reporting emissions and that the
description will reference the relevant
sections of the Transport Rule trading
program regulations and Part 75 and
will state that the requirements may be
modified through EPA approval of
petitions for alternatives to specific
requirements. Finally, consistent with
§§ 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of
the Title V regulations, the final FIPs
provide that a description of the general
monitoring and reporting approach for a
covered unit can be added to, or an
existing description of a unit’s general
monitoring and reporting approach can
be changed, in a Title V permit, using
minor permit modification procedures,
provided that the approach being
described in the changed or new general
description and the requirements
applicable to that approach are already
incorporated elsewhere in the permit.
As a result, minor permit modification
procedures can be used to revise a
covered unit’s Title V permit to be
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consistent with the monitoring and
reporting approach, or any changes in
the approach, allowed for the unit by
EPA through the monitoring system
certification or petition process under
the Transport Rule trading programs.
As new applicable requirements
under Title V, the requirements for
covered units under the final FIPs will
be incorporated into covered sources’
existing Title V permits either pursuant
to the provisions for reopening for cause
(40 CFR 70.7(f) and 40 CFR 71.7(f)) or
the permit renewal provisions (40 CFR
70.7(c) and 71.7(c)).85 In contrast to the
approach in CAIR of imposing
permitting requirements and deadlines
independent of those under Title V, the
approach to permitting under the final
FIPS of imposing no independent
permitting requirements should reduce
the burden on sources already required
to be permitted under Title V and on
permitting authorities. For sources
newly subject to Title V that will also
be covered sources under the final FIPs,
the initial Title V permit issued
pursuant to 40 CFR 70.7(a) will address
the final FIP requirements.
In order to ensure that covered
sources’ Title V permit provisions
concerning the final FIPs will reflect the
Transport Rule trading program
requirements and flexibilities properly
and in a manner consistent from permit
to permit, EPA intends to issue
guidance to assist permitting
authorities. This guidance would
include information on permit issuance
and permit modification requirements,
as well as a permit content template that
will identify the applicable
requirements under the applicable
Transport Rule trading program and
thereby ensure that they will be
correctly and comprehensively reflected
in each permit in a manner that will
reduce the burden on sources and
permitting authorities related to the
issuance of the permit and will reduce
the need for permit revisions.
2. New Source Review
a. Background
EPA recognizes that, following the
vacatur of the new source review (NSR)
pollution control project exemption in
New York v. EPA, 413 F.3d 3, 40–41
(D.C. Cir. 2005), pollution control
projects, including pollution control
projects constructed to comply with this
85 A permit is reopened for cause if any new
applicable requirements (such as those under a FIP)
become applicable to a covered source with a
remaining permit term of 3 or more years. If the
remaining permit term is less than 3 years, such
new applicable requirements will be added to the
permit during permit renewal. See 40 CFR
70.7(f)(1)(i) and 71.7(f)(1)(i).
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rule, have the potential to trigger NSR
permitting.
This issue was previously addressed
in the context of CAIR. On December 20,
2005, the EPA agreed to reconsider one
specific aspect of CAIR. In that notice,
EPA granted reconsideration and sought
comment on the potential impact of the
opinion in New York v. EPA, which
vacated the previously existing NSR
exemption for certain environmentally
beneficial pollution control projects. For
this reconsideration, EPA conducted an
analysis which showed that the court
decision did not impact the CAIR
analyses. Details of this analysis can be
found in a technical support document
which is available on EPA’s Web site at:
https://epa.gov/cair/pdfs/0053-2263.pdf
Because GHG emissions were not
considered by EPA to be air pollutants
within the meaning of the CAA at the
time of CAIR, GHG emissions were not
addressed in the 2005 analysis. GHG
requirements related to the component
of NSR concerning the Prevention of
Significant Deterioration (‘‘PSD’’)
program are addressed in EPA’s
‘‘Interpretation of Regulations that
Determine Pollutants Covered by Clean
Air Act Permitting Programs,’’ 75 FR
17004 (April 2, 2010), and ‘‘Prevention
of Significant Deterioration and Title V
Greenhouse Gas Tailoring Rule,’’ 75 FR
(June 3, 2010) (‘‘Tailoring Rule’’).
Generally, as discussed in those actions,
major stationary sources will be
required to address GHG emissions as
part of the PSD program if these sources
emit GHG in amounts that equal or
exceed the thresholds in the Tailoring
Rule. Major sources that undergo a
modification, including the addition of
pollution control equipment, will trigger
PSD requirements for their emissions of
GHG if such emissions increase by at
least 75,000 86 tons per year of CO2
equivalent (CO2e).
b. Proposed Rule
In the proposed rule, EPA presented
the following conclusions:
(1) The 2005 analysis remains current
and relevant for all pollutants except for
GHG, and it shows that NSR
requirements would not significantly
impact the construction of controls that
86 We note that, for sources that are modifying
and are not subject to PSD for emissions of a nonGHG pollutant, in order to be subject to PSD for
GHGs the source must not only have an emissions
increase of 75,000 TPY CO2e, but must also have
a PTE of at least 100,000 TPY CO2e and 100 TPY
mass GHG. See 40 CFR 52.21(b)(49)(v)(b). However,
since it is reasonable to assume that all sources that
are potentially subject to the Transport Rule will
have a PTE of at least 100,000 TPY CO2e and 100
TPY, for the purposes of discussions in this section
we will only note the requirement to have an
emissions increase of 75,000 TPY CO2e.
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are installed to comply with the
proposed Transport Rule.
(2) It is very unlikely that pollution
control projects would cause GHG
increases that would exceed the 75,000
tons per year threshold.
Consistent with these proposed
conclusions, EPA also concluded that
there would be no significant impacts
from NSR for any pollution control
projects resulting from the proposed
rule such as low-NOX burners, SO2
scrubbers, or SCR. EPA requested
comment on this issue.
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c. Public Comments
EPA received a number of comments
on the NSR issue, which can be divided
into four types of comments: (1)
Comments related to GHGs, (2)
comments related to sulfuric acid mist,
(3) comments related to CO emission
increases from low-NOX burners, and (4)
suggested changes to the EPA rules.
Greenhouse Gases. A number of
commenters recommended that EPA
should document and substantiate its
conclusion that greenhouse gases would
be unlikely to trigger NSR requirements.
Other commenters suggested that some
units installing a FGD scrubber could
exceed the 75,000 ton threshold for
GHGs in the Tailoring Rule by emitting
CO2 produced from the chemical
reaction of SO2 with limestone.
Commenters also suggested that NSR
applicability for GHGs would also need
to consider that an FGD would consume
1–3 percent of a scrubbed unit’s
generation, referred to as ‘‘parasitic
load,’’ which (all else held equal) lowers
that unit’s net generation.87
Commenters argued that any postretrofit increase in generation to offset
that ‘‘parasitic load’’ could lead to GHG
increases potentially exceeding the
75,000 ton threshold.
Sulfuric Acid Mist. Two commenters
noted that use of high sulfur fuels, in
combination with SCR, can lead to
increases in sulfuric acid mist, a
pollutant regulated under NSR. One of
these commenters noted that reagent
injection was necessary to avoid
triggering NSR for sulfuric acid mist
when their SCR was installed.
Carbon Monoxide (CO). One
commenter believed that EPA’s 2005
analysis may not be adequate as it
related to carbon monoxide emission
increases that result from installation of
low-NOX burners. The commenter noted
EPA’s statement in the 2005 analysis
that read as follows: ‘‘Since the NOX
87 ‘‘Net generation’’ refers to total generation
minus the amount of power consumed on-site for
various purposes, including operation of pollution
control equipment.
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removal efficiencies used in EPA’s
analysis are not aggressive, it is believed
that the units installing combustion
controls can opt for moderate levels of
overfire air flow rates and still achieve
the NOX reduction levels projected in
EPA’s analysis, without causing
significant increases in the CO and
unburned carbon emissions.’’ The
commenter suggested that the transport
rule NOX may be more aggressive than
CAIR and thus EPA should conduct a
review to determine whether EPA
retains the same conclusion regarding
CO emissions.
Recommended Rule Changes. Some
commenters suggested changes to EPA
rules to address their concerns that
control equipment installed as a result
of the Transport Rule could trigger NSR.
Some commenters suggested that EPA
craft an exclusion from NSR in the
Transport Rule. One of these
commenters suggested that EPA could
do this by: (1) Providing special
definition of baseline actual emissions;
(2) a causation determination
specifically tied to the Transport Rule;
or (3) interpret the term ‘‘stationary
source’’ in CAA 110(a)(4) in a way that
doesn’t impede Transport Rule
compliance.
Other commenters expressed the
concern that if NSR is triggered, the
proposed Transport Rule did not allow
enough time for compliance for sources
needing to install control equipment.
These commenters recommend that EPA
should waive Transport Rule
requirements or provide extra
allowances until NSR review is
complete.
d. Final Rule and Responses to
Comments
Greenhouse Gases. EPA has carefully
reviewed relevant data in assessing the
comments suggesting that NSR
permitting would likely be triggered for
facilities installing FGD scrubbers to
comply with this rule. EPA believes that
sources installing FGD to comply with
the Transport Rule can achieve those
installations without triggering NSR.
EPA notes that its forecast of the
number and extent of FGD scrubber
installations substantially decreased
since the time of proposal. For the
proposed rule, EPA modeled 14 GW of
FGD retrofit installations by 2014. For
the final rule, EPA models a total of 5.7
GW of wet FGD installations from 7
units at 5 plants.
There are two factors associated with
wet FGD scrubbers that commenters
suggested individually or in
combination could lead to increases
above the 75,000 tons per year threshold
in the Tailoring Rule. The first is the
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CO2 chemically produced from the
reaction of SO2 with limestone in wet
FGD scrubbers. The second is that
owners or operators of the affected units
may desire to increase coal usage after
the retrofit is made to offset the
‘‘parasitic load’’ that is consumed onsite in order to operate the scrubber.
With respect to chemically produced
CO2, EPA concludes that only in very
limited circumstances when installation
of a scrubber is coupled with a change
to considerably higher sulfur coal could
installation of a wet limestone scrubber
be associated with a more than 75,000
ton increase in CO2 emissions. EPA
finds this possibility unlikely to occur.
For example, EPA’s acid rain emissions
reporting system shows that the plant
with the greatest emissions from
unscrubbed units in 2009 emitted about
103,000 tons of SO2 from those units. If
this plant installed a wet limestone
scrubber assumed to reduce those SO2
emissions by 96 percent, EPA calculates
that chemically produced CO2 could
increase emissions by:
103,000 × (0.96) × (44/64) = 67,980 tons
CO2.88
Therefore, EPA finds that all currently
uncontrolled units are technically
capable of retrofitting with wet FGD
without chemically produced CO2
increases leading to a triggering of NSR.
In limited circumstances, an owner or
operator may elect to switch fuels to a
significantly higher-sulfur coal
subsequent to FGD installation and may
risk an increase in chemically produced
CO2 emissions that would trigger NSR,
but such a decision is not necessary in
order to successfully install and operate
the scrubber as a strategy for compliance
with Transport Rule requirements.
With respect to the ‘‘parasitic load’’
issue, EPA estimates that today’s wet
FGD retrofit technology would consume
typically about 1.7 percent of on-site
generation.89 If a facility made no other
changes to its operation other than
installing an FGD retrofit, that facility’s
CO2 emissions from fuel combustion
would remain constant. It is possible,
however, that a source’s owner or
operator may elect to increase coal
usage by some amount after retrofitting
FGD, if for example the owner or
operator desires to increase net
generation after retrofitting. Under NSR,
any such source would be able to
88 The factor 44/64 reflects the relative molecular
weight of CO2 and SO2, respectively. A wet FGD’s
removal of one ton of SO2 involves a chemical
reaction that releases the equivalent molecular
weight of CO2 (thus equaling 44/64 of a ton of CO2
emissions).
89 Documentation Supplement for EPA Base Case
v.4.10_FTransport—Updates for Final Transport
Rule.
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compare such a CO2 emissions increase
against the highest average annual
emissions in any consecutive 24-month
period from a 5-year historic baseline.
Therefore, a unit retrofitting a scrubber
under the Transport Rule may be able to
increase its CO2 emissions by more than
75,000 tons without triggering NSR if
that increase would register as less than
75,000 tons against a higher emissions
level in the aforementioned NSR
baseline.
EPA also notes that scrubber
installations provide facilities with the
opportunity to make other capital
improvements at the unit on which the
scrubber is installed to improve the
efficiency of boilers, steam turbines,
motors, other auxiliary equipment, and
plant control systems. Such
improvements could allow a retrofitting
unit to lower its CO2 output rate such
that a subsequent decision to increase
net generation may not result in
increased coal use, or may limit any CO2
emission increase to less than the
75,000 tons per year threshold for
triggering NSR.
As discussed in section VII.C, EPA
notes that the Transport Rule does not
mandate any specific control activity,
including scrubber retrofitting, as a
compliance strategy for units within a
state to meet that state’s SO2 budget. As
demonstrated by EPA’s ‘‘no FGD’’
sensitivity analysis described in VII.C,
covered sources within the Group 1
states are capable of meeting their
emission reduction obligations through
a variety of emission reduction
strategies even if no unit is able to
complete a scrubber installation by
2014. Therefore, EPA does not believe
that NSR permitting presents an
obstacle in any way to Transport Rule
compliance, even if a given unit
retrofitting with FGD triggers NSR for
CO2.
For some plants, EPA’s IPM modeling
forecasts installation and operation of
dry sorbent injection (DSI) systems. EPA
does not believe any of these systems
would result in CO2 emission increases
above the 75,000 ton threshold.
Moreover, given the relatively short
construction schedule for DSI systems,
EPA believes that if any of the plants
did require NSR permitting, installation
of DSI could still be accomplished by
2014.
In summary, EPA believes that the
operators of plants projected to install
scrubbers for Transport Rule SO2
reductions could readily develop
workable compliance strategies whether
or not such an installation would trigger
NSR. Plant owners could readily
develop strategies to avoid emission
increases that would trigger NSR,
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including but not limited to alternative
SO2 reduction strategies or technologies,
efficiency improvements, or the ability
to adjust net electricity generation to
prevent a 75,000 ton increase in CO2
emissions. EPA believes that projected
scrubber installations under the
Transport Rule are broadly unlikely to
trigger NSR, but even in the limited
conditions where such a triggering may
occur, the NSR permitting process
would not infringe on a state’s ability to
comply with its budgets under the
Transport Rule. (See section VII.C for
more details on EPA’s analysis of a ‘‘no
FGD’’ sensitivity supporting these
points.)
Sulfuric Acid Mist. EPA continues to
conclude that, consistent with the 2005
TSD, sulfuric acid mist increases due to
compliance with this rule are very
unlikely to trigger NSR permitting. Such
increases are most commonly seen from
installation of SCR units on facilities
with relatively high sulfur coal.
However, as acknowledged by one of
the commenters, engineering solutions
have been developed to prevent such
increases, and EPA believes that facility
owners would take this into account in
designing such an SCR system.
Moreover, EPA’s IPM modeling of the
NOX budgets in the final rule suggests
that no new SCR units will result from
the final rule.
Carbon Monoxide. EPA concludes
that any NSR permitting required due to
CO increases associated with NOX
controls should not hinder the ability of
sources to comply with Transport Rule
requirements. For states that were
included in the CAIR for either ozone,
PM2.5, or both, EPA finds no evidence to
suggest that the NOX control
requirements of the Transport Rule
would require more aggressive controls
triggering NSR. As EPA’s baseline
analysis acknowledges, many sources in
these states installed NOX controls to
comply with CAIR. In addition, their
historic emissions reflect operation of
these controls and there is no evidence
to suggest that the Transport Rule will
require sources to operate these controls
more aggressively, thereby increasing
CO emissions above the relevant
threshold and triggering NSR. In a few
states that were not covered by CAIR, a
limited number of facilities may install
new combustion controls (such as lowNOX burners, overfire air, or other
combustion controls or upgrades) as a
result of the Transport Rule. EPA
expects relatively few such installations,
and believes that NSR permitting, if
required, is not an obstacle to
compliance with the rule. First, EPA
believes that NSR permitting should be
relatively straightforward for these
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installations and that the BACT
determination for CO will be very
straightforward. EPA expects a
relatively short time period for
permitting, and as discussed later, EPA
is planning to initiate actions that will
further expedite any required
permitting.
Second, EPA notes that the rule
achieves reductions through a trading
program rather than direct control
requirements. Accordingly, even if a few
installations do not have controls in
place at the very beginning of the
compliance period, this should not
hinder the ability of states to meet their
ozone-season NOX budgets. Covered
sources have a suite of NOX pollution
control strategies and technologies
available to them, including coal
selection, selective non-catalytic
reduction, gas re-burn, low-NOX burner
and overfire air installations or
upgrades, and neural network
optimization of combustion controls
operation. Sources may consider all of
these technologies and strategies, which
can be designed and operated so as to
minimize CO emission increases that
may otherwise trigger NSR. EPA also
notes that during the downtime for
installation of the construction controls,
there would be no NOX emissions, and
thus the source’s allowance holding
requirements would also be lower for
that period.
Recommended Rule Changes. EPA
disagrees with commenters who
suggested rule changes, either to the
NSR program or to this rule, to account
for installations triggering NSR. As
noted above, EPA concludes that NSR
would be triggered at most for just a few
of the projected control installations.
EPA believes, however, that even if
required these NSR permits would
likely be issued in a timely manner
given the overall environmental benefits
resulting from the control equipment
installation. In addition, this rule’s
requirements are based on a flexible
trading approach rather than a direct
control approach. Accordingly, if this
affect occurs for only a few installations,
EPA believes that any extra emissions
that occur during the relatively short
time needed to obtain an NSR permit
could be accommodated within the
overall trading system.
Expediting Permitting. In the limited
circumstances where pollution control
installations under the Transport Rule
may trigger NSR, we also note that an
expedited permitting process can occur
with sufficient time to obtain permits
and achieve emission reductions under
the Transport Rule programs. For this
reason, we strongly encourage
permitting authorities to expedite
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permitting for any such projects, which
are likely to be very limited in number.
To ensure that the permitting decisions
are expedited, separate from this
rulemaking EPA will provide assistance
and guidance in order to expedite
issuance of any such permits. For
example, we are considering assistance
that would serve to expedite BACT
reviews or required air quality analysis.
EPA requests early notification of any
specific cases where such guidance and
assistance may be needed.
ebenthall on DSK6TPTVN1PROD with RULES2
J. How the Program Structure Is
Consistent With Judicial Opinions
Interpreting the Clean Air Act
The air quality-assured trading
programs established by this rule
eliminate all of the emissions that EPA
has identified as significantly
contributing to downwind
nonattainment or interference with
maintenance 90 in a manner that is
consistent with section 110(a)(2)(D)(i) of
the CAA as interpreted by the DC
Circuit in North Carolina, 531 F.3d 896.
The FIPs finalized in this action require
sources to participate in air qualityassured interstate emission trading
programs that include provisions to
ensure that no state’s emissions exceed
that state’s budget with variability limit.
These assurance provisions, combined
with the requirement that all sources
hold emission allowances sufficient to
cover their emissions, effectuate the
requirement that emission reductions
occur within the state. See 42 U.S.C.
7410(a)(1)(2)(D).
The state budgets developed in this
rule represent an estimate of the
emissions that will remain in a given
state after the elimination of all
emissions in that state that EPA has
determined must be prohibited pursuant
to section 110(a)(2)(D)(i)(I). However, for
the reasons explained above, the
amount of emissions that remain after
the requirements of 110(a)(2)(D)(i)(I) are
satisfied may vary. EPA recognizes that
shifts in generation due to, among other
90 As explained in greater detail in Section VI of
this notice, for each covered state, EPA has
identified emissions that must be prohibited
pursuant to section 110(a)(2)(D)(i)(I). In most
instances, EPA has determined that elimination of
such emissions is sufficient to satisfy the
requirements of that section. Thus, in these
instances, the budgets represent an estimate of the
emissions that will remain after the elimination of
all emissions in that state that significantly
contribute to nonattainment or interfere with
maintenance of the NAAQS in another state. In a
few limited instances, however, EPA determined
that elimination of the emissions is necessary but
may not be sufficient to satisfy the requirements of
that section. In these instances, the budgets
represent an estimate of the emissions that will
remain after the elimination of all emissions that
EPA, at this time, has determined must be
eliminated.
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things, changing weather patterns,
demand growth, or disruptions in
electricity supply from other units can
affect the amount of generation needed
in a specific state and thus baseline EGU
emissions from that state. Because a
state’s significant contribution to
nonattainment or interference with
maintenance is defined by EPA as all
emissions that can be eliminated for a
specific cost (as explained above, using
air quality considerations to identify
this cost threshold), and because EGU
baseline emissions are variable, the
amount of emissions remaining in a
state after all significant contribution or
interference with maintenance is
eliminated is also variable. In other
words, EGU emissions in a state whose
sources have installed all controls and
taken all measures necessary to
eliminate its significant contribution to
nonattainment or interference with
maintenance could exceed the state
budget without variability.
For this reason, EPA determined that
it is appropriate for the program to
recognize the inherent variability in
state EGU emissions. The program does
so by identifying a variability range for
each state in the program. The assurance
provisions in the program, in turn, limit
a state’s emissions to the state’s budget
with variability limit.
In addition, the requirement that all
sources hold emission allowances
sufficient to cover their emissions (and
the fact that the total number of
emission allowances allocated will be
equal to the sum of all state budgets
without variability) ensures that the use
of variability limits both takes into
account the inherent variability of
baseline EGU emissions in individual
states (i.e., the variability of total state
EGU emissions before the elimination of
significant contribution or interference
with maintenance) and recognizes that
this variability is not as great in a larger
region. The variability of emissions
across a larger region is not as large as
the variability of emissions in a single
state for several reasons. Increased EGU
emissions in one state in one control
period often are offset by reduced EGU
emissions in another state within the
control region in the same control
period. In a larger region that includes
multiple states, factors that affect
electricity generation, and thus EGU
emission levels, are more likely to vary
significantly within the region so that
resulting emission changes in different
parts of the region are more likely to
offset each other. For example, a broad
region can encompass states with
differing weather patterns, with the
result that increased electricity demand
and emissions due to weather in one
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state may be offset by decreased demand
and emissions due to weather in another
state. By further example, a broad region
can encompass states with differing
types of industrial and commercial
electricity end-users, with the result that
changes in electricity demand and
emissions among the states due to the
effect of economic changes on industrial
and commercial companies may be
offsetting. Similarly, because states in a
broad region may vary in their degree of
dependence on fossil-fuel-based electric
generation, the impact of an outage of
non-fossil-fuel-based generation (e.g., a
nuclear plant) in one state may have a
very different impact in that state than
on other states in the region. Thus, EPA
does not believe it is necessary to allow
total regional allowance allocations for
the states covered by a given trading
program to exceed the sum of all state
budgets without variability for these
states.
For these reasons, the fact that the use
of state budgets with variability limits
may allow limited shifting of emissions
between states is not inconsistent with
the court’s holding that emission
reductions must occur ‘‘within the
state.’’ North Carolina, 531 F.3d at 907.
Under the FIPs, no state may emit more
than its budget with variability limit
and total emissions cannot exceed the
sum of all state budgets without
variability. This approach takes into
account the inherent variability of the
baseline emissions without excusing
any state from eliminating its significant
contribution to nonattainment or
interference with maintenance. It is thus
consistent with the statutory mandate of
section 110(a)(2)(D)(i)(I) as interpreted
by the Court.
Most commenters voiced support for
a remedy option that allows some
degree of interstate trading. However,
one commenter argued that the structure
of the preferred trading remedy that
EPA proposed is legally problematic.
The program, the commenter argues,
provides no legal assurance that the
variability margins will be used by
market participants to account for
variability. The commenter does not
suggest a solution, but instead says, if a
solution cannot be found, EPA should
not allow any amount of interstate
trading.
EPA disagrees with the commenter
that the structure of the preferred
interstate trading program is legally
problematic. In North Carolina, the
Court held that the CAIR interstate
trading programs were inconsistent with
section 110(a)(2)(D)(i)(I), concluding
that ‘‘EPA’s apportionment decisions
have nothing to do with each state’s
‘significant contribution’ ’’ (531 F.3d at
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907) and that ‘‘EPA is not exercising its
section 110(a)(2)(D)(i)(I) duty unless it is
promulgating a rule that achieves
something measurable toward the goal
of prohibiting sources ‘within the State’
from contributing to nonattainment or
interfering with maintenance ‘in any
other State.’ ’’ (531 F.3d at 908). It
emphasized that ‘‘[t]he trading program
is unlawful, because it does not connect
states’ emission reductions to any
measure of their own significant
contributions. To the contrary, it relates
their SO2 reductions to their Title IV
allowances. * * * The allocation of
NOX caps is similarly arbitrary because
EPA distributed allowances simply in
the interest of fairness.’’ 531 F.3d at 930.
As explained in this rule, EPA has
addressed these concerns by using
source specific analysis to identify each
individual state’s significant
contribution to nonattainment and
interference with maintenance, and
including assurance provisions to
ensure that the necessary reductions
occur in each state. The Court did not
go further to prohibit all interstate
trading. In fact, it notes that ‘‘after
rebuilding, a somewhat similar CAIR
may emerge’’ (531 F.3d at 930). For all
of these reasons, EPA does not believe
the opinion in North Carolina can be
read to stand for the proposition that no
interstate trading can be allowed unless
the specific reasons behind market
participants’ decisions to purchase
allowances can be ascertained. Because
allowance purchase decisions are likely
to be based on multiple factors, which
can include the desire to hedge against
potential emission variability as well as
to address actually occurring variability,
requiring ascertainment of the specific
reasons for allowance purchases would
be tantamount to prohibiting all
interstate trading.
Moreover, as discussed above,
variability is inherent to the operation of
the electric generation system and thus
to emissions from this sector. In fact,
variability in emissions occurs every
year in every state and, like variability
of year-to-year weather conditions
(which is a major cause of emission
variability), cannot be accurately
predicted. See the Power Sector
Variability Final Rule TSD in the docket
for this rulemaking. EPA maintains that
its approach of allowing state EGU
emissions each year to vary by up to the
historically representative, annual
amount of inherent, emission variability
reasonably reflects the realities of the
electric generation system and is
consistent with the North Carolina
decision. In summary, the variability
limits take into account inherent
variability over time of emissions in
each state from this sector while also
ensuring that each state makes
necessary emission reductions to
eliminate significant contribution and
interference with maintenance. EPA
thus concludes that the commenter’s
argument that the use of variability
limits allows sources ‘‘within the state’’
to avoid eliminating their significant
contribution or interference with
maintenance is without merit.
VIII. Economic Impacts of the
Transport Rule
A. Emission Reductions
The projected impacts of this final
rule as presented throughout the
preamble do not reflect minor technical
corrections to SO2 budgets in three
states (KY, MI, and NY) made after the
impact analyses were conducted. These
projections also assumed preliminary
variability limits that were smaller than
the variability limits finalized in this
rule. EPA conducted sensitivity analysis
confirming that these differences do not
meaningfully alter any of the Agency’s
findings or conclusions based on the
projected cost, benefit, and air quality
impacts presented for the final
Transport Rule. The results of this
sensitivity analysis are presented in
Appendix F in the final Transport Rule
RIA.
Table VIII.A–1 presents projected
power sector emissions in the base case
(i.e., without the Transport Rule or
CAIR) compared to projected emissions
with the Transport Rule in 2012 and
2014 for all covered states. Table VIII.A–
2 presents 2005 historical power sector
emissions compared to projected
emissions with the Transport Rule in
2012 and 2014. Note that for ozoneseason emissions, these tables present
results from a modeling scenario that
reflects ozone-season NOX requirements
in 26 states. This modeling differs from
the final Transport Rule because it
includes ozone-season NOX
requirements for six states (Iowa,
Kansas, Michigan, Missouri, Oklahoma,
and Wisconsin) that the final Transport
Rule does not cover (as discussed
previously, EPA is issuing a
supplemental proposal to request
comment on inclusion of these six
states).
TABLE VIII.A–1—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSION REDUCTIONS IN COVERED STATES
WITH THE TRANSPORT RULE COMPARED TO BASE CASE WITHOUT TRANSPORT RULE OR CAIR
[Million tons]
2012
Base case
emissions
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SO2 ...................................................................................
Annual NOX .....................................................................
Ozone-Season NOX .........................................................
Notes: The SO2 and annual NOX emissions
in this table reflect EGUs in the 23 states
covered by this rule for purposes of the 24hour and/or annual PM2.5 NAAQS (Alabama,
Georgia, Illinois, Indiana, Iowa, Kansas,
Kentucky, Maryland, Michigan, Minnesota,
Missouri, Nebraska, New Jersey, New York,
North Carolina, Ohio, Pennsylvania, South
Carolina, Tennessee, Texas, Virginia, West
Virginia, and Wisconsin).
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2012
Transport
rule
emissions
7.0
1.4
0.7
2012
Emission
reductions
3.0
1.3
0.6
The ozone-season NOX emissions reflect
EGUs in the 20 states covered by this rule for
purposes of the ozone NAAQS (Alabama,
Arkansas, Florida, Georgia, Illinois, Indiana,
Kentucky, Louisiana, Maryland, Mississippi,
New Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, and West Virginia) and the
six states that would be covered for the ozone
NAAQS if EPA finalizes its supplemental
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4.0
0.1
0.1
2014
Base case
emissions
6.2
1.4
0.7
2014
Transport
rule
emissions
2.4
1.2
0.6
2014
Emission
reductions
3.9
0.2
0.1
proposal (Iowa, Kansas, Michigan, Missouri,
Oklahoma, and Wisconsin).
Tables VIII.A–3 through VIII.A–5
present projected state-level emissions
with and without the Transport Rule in
2012 and 2014 from fossil-fuel-fired
EGUs greater than 25 MW in covered
states.
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TABLE VIII.A–2—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSION REDUCTIONS IN COVERED STATES
WITH THE TRANSPORT RULE COMPARED TO 2005 ACTUAL EMISSIONS
[Million tons]
SO2 ..........................................................................................................
Annual NOX .............................................................................................
Ozone-Season NOX ................................................................................
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Notes: The SO2 and annual NOX emissions
in this table reflect EGUs in the 23 states
covered by this rule for purposes of the 24hour and/or annual PM2.5 NAAQS (Alabama,
Georgia, Illinois, Indiana, Iowa, Kansas,
Kentucky, Maryland, Michigan, Minnesota,
Missouri, Nebraska, New Jersey, New York,
North Carolina, Ohio, Pennsylvania, South
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2012
Transport
rule
emissions
8.8
2.6
0.9
Carolina, Tennessee, Texas, Virginia, West
Virginia, and Wisconsin).
The ozone-season NOX emissions reflect
EGUs in the 20 states covered by this rule for
purposes of the ozone NAAQS (Alabama,
Arkansas, Florida, Georgia, Illinois, Indiana,
Kentucky, Louisiana, Maryland, Mississippi,
New Jersey, New York, North Carolina, Ohio,
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3.0
1.3
0.6
2012
Emission
reductions
from 2005
5.8
1.3
0.3
2014
Transport
rule
emissions
2.4
1.2
0.6
2014
Emission
reductions
from 2005
6.4
1.4
0.3
Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, and West Virginia) and the
six states that would be covered for the ozone
NAAQS if EPA finalizes its supplemental
proposal (Iowa, Kansas, Michigan, Missouri,
Oklahoma, and Wisconsin).
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2005
Actual
emissions
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B. The Impacts on PM2.5 and Ozone of
the Final SO2 and NOX Strategy
The air quality modeling platform
described in section V was used by EPA
to model the impacts of the final rule
SO2 and NOX emission reductions on
annual average PM2.5, 24-hour PM2.5,
and 8-hour ozone concentrations. In
brief, we ran the CAMx model for the
meteorological conditions in the year of
2005 for the eastern U.S. modeling
domain.91 Modeling was performed for
91 As described in the Air Quality Modeling Final
Rule TSD, the eastern U.S. was modeled at a
horizontal resolution of 12 x 12 km. The remainder
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the 2014 base case and the 2014 air
quality-assured trading (i.e., remedy)
scenario to assess the expected effects of
the final rule on projected PM2.5 and
ozone design value concentrations and
nonattainment and maintenance. The
procedures used to project future design
values and nonattainment and
maintenance are described in section V.
The projected 2014 concentrations of
annual PM2.5, 24-hour PM2.5, and ozone
at each monitoring site in the East for
which projections were made are
provided in the Air Quality Modeling
Final Rule TSD. The number of
nonattainment and/or maintenance sites
in the East for the 2012 base case, 2014
base case, and 2014 remedy for annual
PM2.5, 24-hour PM2.5, and ozone are
provided in Table VIII.B–1.92 The
average and peak reductions in annual
PM2.5, 24-hour PM2.5, and ozone
predicted at 2012 nonattainment and/or
maintenance sites due the emission
reductions between 2012 and the 2014
remedy are provided in Table VIII.B–2.
of the U.S. was modeled at a resolution of 36 x 36
km.
92 To provide a point of reference, Table VIII.B–
1 also includes the number of nonattainment and/
maintenance sites based on ambient design values
for the period 2003 through 2007.
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TABLE VIII.B–1—PROJECTED REDUCTION IN NONATTAINMENT AND/OR MAINTENANCE PROBLEMS FOR PM2.5 AND OZONE
IN THE EASTERN U.S.
Ambient
(2003–2007)
Annual PM2.5 Nonattainment Sites 93 ........
Annual PM2.5 Maintenance-Only Sites ......
24-hour PM2.5 Nonattainment Sites ..........
24-hour PM2.5 Maintenance-Only Sites .....
Ozone Nonattainment Sites ......................
Ozone Maintenance-Only Sites .................
2012 Base
case
103
22
151
48
104
65
2014 Base
case
12
4
20
21
7
9
2014 remedy
7
3
10
12
4
6
Percent reduction: 2012
base case vs.
2014 remedy
(percent)
0
0
1
4
4
6
100
100
95
81
43
33
Percent reduction: 2014
base case vs.
2014 remedy
100 percent.
100 percent.
90 percent.
67 percent.
No Change.
No Change.
TABLE VIII.B–2—AVERAGE AND PEAK REDUCTION IN ANNUAL PM2.5, 24-HOUR PM2.5, AND OZONE FOR SITES THAT ARE
PROJECTED TO HAVE NONATTAINMENT AND/OR MAINTENANCE PROBLEMS IN THE 2012 BASE CASE
Average reduction:
2012 base Case to
2014 remedy
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Annual PM2.5 Nonattainment Sites .........................................................................................................
Annual PM2.5 Maintenance-Only Sites ...................................................................................................
24-hour PM2.5 Nonattainment Sites ........................................................................................................
24-hour PM2.5 Maintenance-Only Sites ..................................................................................................
Ozone Nonattainment Sites ....................................................................................................................
Ozone Maintenance-Only Sites ..............................................................................................................
The information in Table VIII.B–1
shows that there will be significant
reductions in the extent of
nonattainment and maintenance
problems for annual PM2.5, 24-hour
PM2.5, and ozone between 2012 and
2014 as a result of the emission budgets
in this rule coupled with emission
reductions during this time period from
other existing control programs.
Specifically, the results of the air quality
modeling indicate that no sites are
projected to be in nonattainment or
projected to have a maintenance
problem for annual PM2.5 in 2014 with
the emission reductions expected from
the Transport Rule. As indicated in
Table VIII.B–2, the average reduction in
annual PM2.5 across the twelve 2012
nonattainment sites is 2.73 μg/m3 and
the peak reduction at an individual
nonattainment site is 3.32 μg/m3. Large
reductions are also projected at annual
PM2.5 maintenance-only sites.
For 24-hour PM2.5, we project that the
number of nonattainment sites will be
reduced by 95 percent and the number
of maintenance-only sites by 81 percent
in 2014 compared to the 2012 base case.
The average reduction in 24-hour PM2.5
across the twenty 2012 nonattainment
sites is 6.8 μg/m3 and the peak
reduction at an individual
nonattainment site is 11.7 μg/m3.
Similarly large reductions are projected
93 ‘‘Nonattainment’’ is used to denote sites that
are projected to have both nonattainment and
maintenance problems.
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at 24-hour PM2.5 maintenance-only
sites, as indicated in Table VIII.B–2.
The emission reductions in the
Transport Rule will result in
considerable progress toward attainment
and maintenance at the 5 sites that
remain as nonattainment and/or
maintenance for the 24-hour PM2.5
standard. On average for these 5 sites,
the predicted amount of PM2.5 reduction
in 2014 is 64 percent of what is needed
for these sites to attain and/or maintain
the 24-hour standard.
Thus, the SO2 and NOX emission
reductions which will result from the
Transport Rule will greatly reduce the
extent of PM2.5 nonattainment and
maintenance problems by 2014 and
beyond. As described previously, these
emission reductions are expected to
substantially reduce the number of
PM2.5 nonattainment and/or
maintenance sites in the East and make
attainment easier for those counties that
remain nonattainment by substantially
lowering PM2.5 concentrations in
residual nonattainment sites. The
emission reductions will also help those
locations that may have maintenance
problems.
Based on the 2012 base air quality
modeling for ozone, 16 sites in the East
are projected to be nonattainment or
have problems maintaining the 1997
ozone standard. The summer NOX
reductions are projected to lower 8-hour
ozone concentration by 1.8 ppb, on
average by 2014, at monitoring sites
projected to be nonattainment and/or
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Peak reduction:
2012 base case to
2014 remedy
2.73 μg/m3 .............
2.99 μg/m3 .............
6.8 μg/m3 ...............
6.5 μg/m3 ...............
1.9 ppb ...................
1.8 ppb ...................
3.32 μg/m3.
3.26 μg/m3.
11.7 μg/m3.
11.0 μg/m3.
2.3 ppb.
2.1 ppb.
have maintenance problems in the 2012
base case. We expect that the number of
nonattainment sites will be reduced by
43 percent and the number of
maintenance-only sites by 33 percent in
2014 compared to the 2012 base case.
Thus, our modeling indicates that by
2014 the summer NOX emission
reductions in this rule, coupled with
other existing control programs, will
lower ozone concentrations in the East
and help bring areas closer to
attainment for the 8-hour ozone
NAAQS. As discussed in section III of
this preamble, EPA plans to finalize its
reconsideration of the 2008 revised
ozone NAAQS soon, and these
reductions will help areas achieve those
revised NAAQS.
C. Benefits
1. Human Health Benefit Analysis
To estimate the human health benefits
of the final Transport Rule, EPA used
the BenMAP model to quantify the
changes in PM2.5 and ozone-related
health impacts and monetized benefits
based on changes in air quality. For
context, it is important to note that the
magnitude of the PM2.5 benefits is
largely driven by the concentration
response function for premature
mortality. Experts have advised EPA to
consider a variety of assumptions,
including estimates based both on
empirical (epidemiological) studies and
judgments elicited from scientific
experts, to characterize the uncertainty
in the relationship between PM2.5
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concentrations and premature mortality.
For this rule we cite two key empirical
studies, one based on the American
Cancer Society cohort study 94 and the
other based on the extended Six Cities
cohort study.95
The estimated benefits of this rule are
substantial, particularly when viewed
within the context of the total public
health burden of PM2.5 and ozone air
pollution. A recent EPA analysis
estimated that 2005 levels of PM2.5 and
ozone were responsible for between
130,000 and 320,000 PM2.5-related and
4,700 ozone-related premature deaths,
or about 6.1 percent of total deaths from
all causes in the continental U.S. (using
the lower end of the range for premature
deaths).96 In other words, 1 in 20 deaths
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94 Pope et al., 2002. ‘‘Lung Cancer,
Cardiopulmonary Mortality, and Long-term
Exposure to Fine Particulate Air Pollution.’’ Journal
of the American Medical Association. 287:1132–
1141.
95 Laden et al., 2006. ‘‘Reduction in Fine
Particulate Air Pollution and Mortality.’’ American
Journal of Respiratory and Critical Care Medicine.
173:667–672.
96 Fann N, Lamson A, Wesson K, Risley D,
Anenberg SC, Hubbell BJ. Estimating the National
Public Health Burden Associated with Exposure to
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in the U.S. is attributable to PM2.5 and
ozone exposure. This same analysis
attributed almost 200,000 non-fatal
heart attacks, 90,000 hospital
admissions due to respiratory or
cardiovascular illness, 2.5 million cases
of aggravated asthma among children,
and many other human health impacts
to exposure to these two air pollutants.
We estimate that PM2.5 improvements
under the Transport Rule will, starting
in 2014, annually reduce between
13,000 and 34,000 PM2.5-related
premature deaths, 15,000 non-fatal heart
attacks, 8,700 incidences of chronic
bronchitis, 8,500 hospital admissions,
and 400,000 cases of aggravated asthma
while also reducing 10 million days of
restricted activity due to respiratory
illness and approximately 1.7 million
work-loss days. We also estimate
substantial health improvements for
children from fewer cases of upper and
lower respiratory illness and acute
bronchitis.
Ozone health-related benefits are
expected to occur during the summer
Ambient PM2.5 and Ozone. Risk Analysis; 2011 In
Press.
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48309
ozone season (usually ranging from May
to September in the eastern U.S.). Based
upon modeling for 2014, annual ozone
related health benefits are expected to
include between 27 and 120 fewer
premature mortalities, 240 fewer
hospital admissions for respiratory
illnesses, 86 fewer emergency room
admissions for asthma, 160,000 fewer
days with restricted activity levels, and
51,000 fewer days where children are
absent from school due to illnesses.
Table VIII.C–1 presents the primary
estimates of annual reduced incidence
of PM2.5 and ozone-related health effects
for the final rule based on 2014 air
quality improvements. When adding the
PM and ozone-related mortalities
together, we find that the Transport
Rule will yield between 13,000 and
34,000 fewer premature mortalities
annually. By 2014, in combination with
other federal and state air quality
actions, the Transport Rule will address
a substantial fraction of the total public
health burden of PM2.5 and ozone air
pollution.
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Only a subset of the expected
visibility benefits—those for Class I
areas—are included in the monetary
benefit estimates we project for this
rule. We anticipate improvement in
visibility in residential areas where
people live, work, and recreate within
the Transport Rule region for which we
are currently unable to monetize
benefits. For the Class I areas we
estimate annual benefits of $4.1 billion
beginning in 2014 for visibility
improvements. The value of visibility
benefits in areas where we are unable to
monetize benefits could be substantial.
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3. Benefits of Reducing GHG Emissions
When fully implemented in 2014, the
Transport Rule will reduce emissions of
CO2 from electrical generating units by
about 25 million metric tons annually.
Using a ‘‘social cost of carbon’’ (SCC)
estimate that accounts for the marginal
dollar value (i.e., cost) of climate-related
damages resulting from CO2 emissions,
previous analyses, including the RIA for
the Final Rulemaking to Establish LightDuty Vehicle Greenhouse Gas Emissions
Standards and Corporate Average Fuel
Efficiency Standards, have found the
total benefit of CO2 reductions is
substantial. The monetary value of these
avoided damages also grows over time.
Readers interested in learning more
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about the calculation of the SCC metric
should refer to the SCC TSD, Social Cost
of Carbon for Regulatory Impact
Analysis Under Executive Order 12866
[Docket No. EPA–HQ–OAR–2009–
0472].
4. Total Monetized Benefits
Table VIII.C–2 presents the estimated
annual monetary value of reductions in
the incidence of health and welfare
effects. These estimates account for
increases in the value of risk reduction
over time. Total monetized benefits are
driven primarily by the reduction in
premature fatalities each year, which
account for between 89 and 96 percent
of total benefits.
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2. Quantified and Monetized Visibility
Benefits
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5. How do the benefits in 2012 compare
to 2014?
The magnitude of SO2 emission
reductions achieved under the rule is
actually larger in 2012 than in 2014, due
to substantial emission reductions
expected to occur in the baseline (i.e.,
unrelated to the Transport Rule)
between those years. As a consequence,
EPA expects correspondingly greater
reductions in harmful effects to accrue
in 2012 compared to 2014.
As presented in Table VIII.C–1, the
Transport Rule is expected to prevent
between 13,000 and 34,000 premature
deaths annually from 2014 onward due
to reductions in ambient PM2.5
concentrations, which are most
significantly impacted by SO2 emission
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reductions. Based on EPA’s analysis of
power sector emission reductions under
the Transport Rule, the decline in SO2
in 2012 is 4 percent greater than the
decline in SO2 in 2014 in the states
modeled. EPA therefore anticipates that
the Transport Rule will deliver greater
reductions in ambient PM2.5
concentrations in 2012 and increased
annual benefits to human health and
welfare beyond those presented in this
section.
6. How do the benefits compare to the
costs of this final rule?
The estimated annual private costs to
implement the emission reduction
requirements of the final rule for the
Transport Rule states are $1.85 billion
in 2012 and $0.83 billion in 2014 (2007
$). These costs are the annual
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48313
incremental electric generation
production costs that are expected to
occur with the Transport Rule. The EPA
uses these costs as compliance cost
estimates in developing costeffectiveness estimates.
In estimating the net benefits of
regulation, the appropriate cost measure
is ‘‘social costs.’’ Social costs represent
the welfare costs of the rule to society.
These costs do not consider transfer
payments (such as taxes) that are simply
redistributions of wealth. The social
costs of this rule are estimated to be
approximately $0.81 billion in 2014
assuming either a 3 percent discount
rate or a 7 percent discount rate. Thus,
the annual net benefit (social benefits
minus social costs) as shown in Table
VIII.C–3 for the Transport Rule is
approximately $120 to $280 billion or
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$110 to $250 billion (3 percent and 7
percent discount rates, respectively) in
2014. Implementation of the rule is
expected to provide society with a
substantial net gain in social welfare
based on economic efficiency criteria.
A listing of the benefit categories that
could not be quantified or monetized in
our benefit estimates is provided in
Table VIII.C–4.
TABLE VIII.C–3—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF THE FINAL TRANSPORT RULE IN 2014
[Billions of 2007$] a
Transport Rule remedy
(billions of 2007 $)
Description
3% discount rate
Social costs ......................................................................................................................................
Total monetized benefits b ...............................................................................................................
Net benefits (benefits-costs) ............................................................................................................
$0.81 .........................
$120 to $280 .............
$120 to $280 .............
7% discount rate
$0.81.
$110 to $250.
$110 to $250.
a All
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estimates are for 2014, and are rounded to two significant figures.
b The total monetized benefits reflect the human health benefits associated with reducing exposure to PM
2.5 and ozone and the welfare benefits associated with improved visibility in Class I areas. The reduction in premature mortalities account for over 90 percent of total monetized
PM2.5 and ozone benefits.
The annualized regional cost of the
rule, as quantified here, is EPA’s best
assessment of the cost of implementing
the Transport Rule. These costs are
generated from rigorous economic
modeling of changes in the power sector
expected from the rule. This type of
analysis, using IPM, has undergone peer
review and been upheld in federal
courts. The direct cost includes, but is
not limited to, capital investments in
pollution controls, operating expenses
of the pollution controls, investments in
new generating sources, and additional
fuel expenditures. The EPA believes
that these costs reflect, as closely as
possible, the additional costs of the
Transport Rule to industry. The
relatively small cost associated with
monitoring emissions, reporting, and
recordkeeping for affected sources is not
included in these annualized cost
estimates, but EPA has done a separate
analysis and estimated the cost to be
about $26 million (see section XII.B,
Paperwork Reduction Act). However,
there may exist certain costs that EPA
has not quantified in these estimates.
These costs may include costs of
transitioning to this rule, such as the
costs associated with the retirement of
smaller or less efficient EGUs,
employment shifts as workers are
retrained at the same company or reemployed elsewhere in the economy,
and certain relatively small permitting
costs associated with Title V that new
program entrants face.
An optimization model was employed
that assumes cost minimization. Costs
may be understated if the regulated
community chooses not to minimize its
compliance costs in the same manner to
comply with the rules. Although EPA
has not quantified these costs, the
Agency believes that they are small
compared with the quantified costs of
the program to the power sector.
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However, EPA’s experience and results
of independent evaluation suggests that
costs are likely to be lower by some
degree (see RIA for details). The
annualized cost estimates presented are
the best and most accurate based upon
available information. In a separate
analysis, EPA estimates the indirect
costs and impacts of higher electricity
prices on the entire economy. These
impacts are summarized in the RIA for
this final rule.
Every benefit-cost analysis examining
the potential effects of a change in
environmental protection requirements
is limited to some extent by data gaps,
model capabilities (such as geographic
coverage), and uncertainties in the
underlying scientific and economic
studies used to configure the benefit and
cost models. Gaps in the scientific
literature often result in the inability to
estimate quantitative changes in health
and environmental effects, or to assign
economic values even to those health
and environmental outcomes that can be
quantified. While uncertainties in the
underlying scientific and economics
literatures (that may result in
overestimation or underestimation of
benefits) are discussed in detail in the
economic analyses and its supporting
documents and references, the key
uncertainties which have a bearing on
the results of the benefit-cost analysis of
this rule include the following:
• EPA’s inability to quantify
potentially significant benefit categories;
• Uncertainties in population growth
and baseline incidence rates;
• Uncertainties in projection of
emission inventories and air quality into
the future;
• Uncertainty in the estimated
relationships of health and welfare
effects to changes in pollutant
concentrations, including the shape of
the C–R function, the size of the effect
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estimates, and the relative toxicity of the
many components of the PM mixture;
• Uncertainties in exposure
estimation; and
• Uncertainties associated with the
effect of potential future actions to limit
emissions.
Despite these uncertainties, we
believe the benefit-cost analysis
provides a reasonable indication of the
expected economic benefits of the
rulemaking in future years under a set
of reasonable assumptions. This
approach calculates a mean value across
value of a statistical life (VSL) estimates
derived from 26 labor market and
contingent valuation studies published
between 1974 and 1991. The mean VSL
across these studies is $6.3 million
(2000$).97 The benefits estimates
generated for this rule are subject to a
number of assumptions and
uncertainties, which are discussed
throughout the RIA document.
As Table VIII.C–2 indicates, total
annual monetary benefits are driven
primarily by the reduction in premature
mortalities each year. Some key
assumptions underlying the primary
estimate for the premature mortality
category include the following:
(1) EPA assumes inhalation of fine
particles is causally associated with
premature death at concentrations near
those experienced by most Americans
on a 24-hour basis. Plausible biological
mechanisms for this effect have been
hypothesized for the endpoints
included in the primary analysis, and
the weight of the available
epidemiological evidence supports an
assumption of causality.
97 In this analysis, we adjust the VSL to account
for a different currency year (2007$) and to account
for income growth to 2014. After applying these
adjustments to the $6.3 million value, the VSL is
$8.7 million.
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
(2) EPA assumes all fine particles,
regardless of their chemical
composition, are equally potent in
causing premature mortality. This is an
important assumption, because the
proportion of certain components in the
PM mixture produced via precursors
emitted from EGUs may differ
significantly from direct PM released
from automotive engines and other
industrial sources, but no clear
scientific grounds exist for supporting
differential effects estimates by particle
type.
(3) We assume that the health impact
function for fine particles is linear down
to the lowest air quality levels modeled
in this analysis. Thus, the estimates
include health benefits from reducing
fine particles in areas with varied
concentrations of PM2.5, including both
regions that are in attainment with the
fine particle standard and those that do
not meet the standard down to the
lowest modeled concentrations.
The EPA recognizes the difficulties,
assumptions, and inherent uncertainties
in the overall enterprise. The analyses
upon which the Transport Rule is based
were selected from the peer-reviewed
scientific literature. We used up-to-date
assessment tools, and we believe the
48315
results are highly useful in assessing
this rule.
There are a number of health and
environmental effects that we were
unable to quantify or monetize. A
complete benefit-cost analysis of the
Transport Rule requires consideration of
all benefits and costs expected to result
from the rule, not just those benefits and
costs which could be expressed here in
dollar terms. A listing of the benefit
categories that were not quantified or
monetized in our estimate are provided
in Table VIII.C–4.
TABLE VIII.C–4—UNQUANTIFIED AND NON-MONETIZED EFFECTS OF THE TRANSPORT RULE
Pollutant/Effect
PM: Health a .........................
PM: Welfare .........................
Ozone: Health ......................
Ozone: Welfare ....................
NO2: Health ..........................
NO2: Welfare ........................
SO2: Health ..........................
SO2: Welfare ........................
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Mercury: Health ....................
Mercury: Welfare ..................
Endpoint
Low birth weight.
Pulmonary function.
Chronic respiratory diseases other than chronic bronchitis.
Non-asthma respiratory emergency room visits.
UVb exposure b.
Household soiling.
Visibility in residential areas.
Visibility in non-class I areas and class 1 areas in NW, NE, and Central regions.
UVb exposure b.
Global climate impacts b.
Chronic respiratory damage.
Premature aging of the lungs.
Non-asthma respiratory emergency room visits.
UVb exposure b.
Yields for:
—Commercial forests.
—Fruits and vegetables, and
—Other commercial and noncommercial crops.
Damage to urban ornamental plants.
Recreational demand from damaged forest aesthetics.
Ecosystem functions.
Increased exposure to UVb b.
Climate impacts.
Respiratory hospital admissions.
Respiratory emergency department visits.
Asthma exacerbation.
Acute respiratory symptoms.
Premature mortality.
Pulmonary function.
Commercial fishing and forestry from acidic deposition effects.
Commercial fishing, agriculture and forestry from nutrient deposition effects.
Recreation in terrestrial and estuarine ecosystems from nutrient deposition effects.
Other ecosystem services and existence values for currently healthy ecosystems.
Coastal eutrophication from nitrogen deposition effects.
Respiratory hospital admissions.
Asthma emergency room visits.
Asthma exacerbation.
Acute respiratory symptoms.
Premature mortality.
Pulmonary function.
Commercial fishing and forestry from acidic deposition effects.
Recreation in terrestrial and aquatic ecosystems from acid deposition effects.
Increased mercury methylation.
Incidence of neurological disorders.
Incidence of learning disabilities.
Incidences in developmental delays.
Impact on birds and mammals (e.g., reproductive effects).
Impacts to commercial, subsistence and recreational fishing.
Source: EPA.
a In addition to primary economic endpoints, there are a number of biological responses that have been associated with PM health effects including morphological changes and altered host defense mechanisms. The public health impact of these biological responses may be partly represented by our quantified endpoints.
b May result in benefits or disbenefits.
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
7. What are the unquantified and nonmonetized benefits of the Transport
Rule emission reductions?
Important benefits beyond the human
health and welfare benefits quantified in
this section and the RIA are expected to
occur from this rule. These other
benefits occur directly from NOX and
SO2 emission reductions and from cobenefits due to Transport Rule
compliance. These benefits are listed in
Table VIII.C–4. Some of the more
important examples include: Reduced
acidification and, in the case of NOX,
eutrophication of water bodies; possible
reduced nitrate contamination of
drinking water; and reduced acid and
particulate deposition that causes
damages to cultural monuments, as well
as, soiling and other materials damage.
To illustrate the important nature of
benefit categories EPA is currently
unable to monetize, we discuss four
categories of public welfare and
environmental impacts related to
reductions in emissions required by the
Transport Rule: Reduced acid
deposition, reduced eutrophication of
estuaries, reduced mercury methylation
and deposition, and reduced vegetation
impairment from ozone.
a. What are the benefits of reduced
deposition of sulfur and nitrogen to
aquatic, forest, and coastal ecosystems?
Atmospheric deposition of sulfur and
nitrogen, often referred to as acid rain,
occurs when emissions of SO2 and NOX
react in the atmosphere (with water,
oxygen, and oxidants) to form various
acidic compounds. These acidic
compounds fall to earth in either a wet
form (rain, snow, and fog) or a dry form
(gases and particles). Prevailing winds
can transport acidic compounds
hundreds of miles, across state borders.
These compounds are deposited onto
terrestrial and aquatic ecosystems across
the U.S., contributing to the problems of
acidification.
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(1) Acid Deposition and Acidification of
Lakes and Streams
The extent of adverse effects of acid
deposition on freshwater and forest
ecosystems depends largely upon the
ecosystem’s ability to neutralize the
acid. The neutralizing ability depends
largely on the watershed’s physical
characteristics, such as geology, soils,
and size. A key indicator of neutralizing
ability is termed Acid Neutralizing
Capacity (ANC). Higher ANC indicates
greater ability to neutralize acidity.
Acidic conditions occur more frequently
during rainfall and snowmelt that cause
high flows of water, and less commonly
during low-flow conditions except
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where chronic acidity conditions are
severe. Biological effects are primarily
attributable to a combination of low pH
and high inorganic aluminum
concentrations. Biological effects of
episodes include reduced fish condition
factor—changes in species composition
and declines in aquatic species richness
across multiple taxa, ecosystems and
regions—as well as fish mortality.
Waters that are sensitive to acidification
tend to be located in small watersheds
that have few alkaline minerals and
shallow soils. Conversely, watersheds
that contain alkaline minerals, such as
limestone, tend to have waters with a
high ANC. Areas especially sensitive to
acidification include portions of the
Northeast (particularly, the Adirondack
and Catskill Mountains, portions of New
England, and streams in the midAppalachian highlands) and
southeastern streams. This regulatory
action will decrease acid deposition
within and downwind of the transport
region and is likely to have positive
effects on the health and productivity of
aquatic ecosystems in the region.
deposition. This change in nutrient
availability may reduce the quality of
forest nutrition over the long term.
Evidence suggests that red spruce and
sugar maple in some areas in the eastern
U.S. have experienced declining health
because of this deposition. For red
spruce (Picea rubens), dieback or
decline has been observed across high
elevation landscapes of the northeastern
U.S. and, to a lesser extent, the
southeastern U.S. Acidifying deposition
has been implicated as a causal
factor.100
This regulatory action will decrease
acid deposition within and downwind
of the transport region and is likely to
have positive effects on the health and
productivity of forest systems in the
region.
b. Coastal Ecosystems
(2) Acid Deposition and Forest
Ecosystem Impacts
Acidifying deposition has altered
major biogeochemical processes in the
U.S. by increasing the nitrogen and
sulfur content of soils, accelerating
nitrate and sulfate leaching from soil to
drainage waters, depleting base cations
(especially calcium and magnesium)
from soils, and increasing the mobility
of aluminum. Inorganic aluminum is
toxic to some tree roots. Plants affected
by high levels of aluminum from the
soil often have reduced root growth,
which restricts the ability of the plant to
take up water and nutrients, especially
calcium.98 These direct effects can, in
turn, influence the response of these
plants to climatic stresses such as
droughts and cold temperatures. They
can also influence the sensitivity of
plants to other stresses, including insect
pests and disease,99 leading to increased
mortality of canopy trees.
Both coniferous and deciduous forests
throughout the eastern U.S. are
experiencing gradual losses of base
cation nutrients from the soil due to
accelerated leaching from acidifying
Since 1990, a large amount of research
has been conducted on the impact of
nitrogen deposition to coastal waters.
Nitrogen is often the limiting nutrient in
coastal ecosystems. Increasing the levels
of nitrogen in coastal waters can cause
significant changes to those ecosystems.
In recent decades, human activities have
accelerated nitrogen nutrient inputs,
causing excessive growth of algae and
leading to degraded water quality and
associated impairments of estuarine and
coastal resources.
Atmospheric deposition of nitrogen is
a significant source of nitrogen to many
estuaries. The amount of nitrogen
entering estuaries due to atmospheric
deposition varies widely, depending on
the size and location of the estuarine
watershed and other sources of nitrogen
in the watershed. A recent assessment of
141 estuaries nationwide by the
National Oceanic and Atmospheric
Administration (NOAA) concluded that
19 estuaries (13 percent) suffered from
moderately high or high levels of
eutrophication due to excessive inputs
of both nitrogen and phosphorus, and a
majority of these estuaries are located in
the coastal area from North Carolina to
Massachusetts.101 For estuaries in the
Mid-Atlantic region, the contribution of
atmospheric distribution to total
nitrogen loads is estimated to range
between 10 percent and 58 percent.102
98 U.S. Environmental Protection Agency (U.S.
EPA). 2008. Integrated Science Assessment for
Oxides of Nitrogen and Sulfur—Ecological Criteria
National (Final Report). National
Center for Environmental Assessment, Research
Triangle Park, NC. EPA/600/R–08/139. December.
https://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?
deid=201485.
99 Joslin, J.D., Kelly, J.M., van Miegroet, H. 1992.
Soil chemistry and nutrition of North American
spruce-fir stands: evidence for recent change.
Journal of Environmental Quality, 21, 12–30.
100 DeHayes, D.H., P.G. Schaberg, G.J. Hawley,
and G.R. Strimbeck. 1999. Acid rain impacts on
calcium nutrition and forest health. Bioscience
49(10):789–800.
101 National Oceanic and Atmospheric
Administration (NOAA). 2007. Annual Commercial
Landing Statistics. August. https://www.st.nmfs.
noaa.gov/st1/commercial/landings/annual_
landings.html.
102 Valigura, R.A., R.B. Alexander, M.S. Castro,
T.P. Meyers, H.W. Paerl, P.E. Stacy, and R.E.
Turner. 2001. Nitrogen Loading in Coastal Water
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
Eutrophication in estuaries is
associated with a range of adverse
ecological effects. The conceptual
framework developed by NOAA
emphasizes four main types of
eutrophication effects: low dissolved
oxygen (DO), harmful algal blooms
(HABs), loss of submerged aquatic
vegetation (SAV), and low water clarity.
Low DO disrupts aquatic habitats,
causing stress to fish and shellfish,
which, in the short-term, can lead to
episodic fish kills and, in the long-term,
can damage overall growth in fish and
shellfish populations. Low DO also
degrades the aesthetic qualities of
surface water. In addition to often being
toxic to fish and shellfish, and leading
to fish kills and aesthetic impairments
of estuaries, HABs can, in some
instances, also be harmful to human
health. SAV provides critical habitat for
many aquatic species in estuaries and,
in some instances, can also protect
shorelines by reducing wave strength.
Therefore, declines in SAV due to
nutrient enrichment are an important
source of concern. Low water clarity is
the result of accumulations of both algae
and sediments in estuarine waters. In
addition to contributing to declines in
SAV, high levels of turbidity also
degrade the aesthetic qualities of the
estuarine environment.
Estuaries in the eastern United States
are an important source of food
production, in particular fish and
shellfish production. The estuaries are
capable of supporting large stocks of
resident commercial species, and they
serve as the breeding grounds and
interim habitat for several migratory
species.
This rule is anticipated to reduce
nitrogen deposition within and
downwind of the Transport Rule states.
Thus, reductions in the levels of
nitrogen deposition will have a positive
impact upon current eutrophic
conditions in estuaries and coastal areas
in the region.
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c. Mercury Methylation and Deposition
Mercury is a highly neurotoxic
contaminant that enters the food web as
a methylated compound,
methylmercury.103 The contaminant is
concentrated in higher trophic levels,
including fish eaten by humans.
Experimental evidence has established
Bodies: An Atmospheric Perspective. Washington,
DC: American Geophysical Union.
103 U.S. Environmental Protection Agency (U.S.
EPA). 2008. Integrated Science Assessment for
Sulfur Oxides—Health Criteria (Final Report).
National Center for Environmental Assessment,
Research Triangle Park, NC. September. https://
cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=
198843.
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that only inconsequential amounts of
methylmercury can be produced in the
absence of sulfate. Current evidence
indicates that in watersheds where
mercury is present, increased SOX
deposition very likely results in
methylmercury accumulation in
fish.104 105 The SO2 Integrated Science
Assessment concluded that evidence is
sufficient to infer a causal relationship
between sulfur deposition and increased
mercury methylation in wetlands and
aquatic environments.
d. Ozone Vegetation Effects
Ozone causes discernible injury to a
wide array of vegetation.106 In terms of
forest productivity and ecosystem
diversity, ozone may be the pollutant
with the greatest potential for regionalscale forest impacts.107 Studies have
demonstrated repeatedly that ozone
concentrations commonly observed in
polluted areas can have substantial
impacts on plant function.108 109
Assessing the impact of ground-level
ozone on forests in the eastern United
States involves understanding the risks
to sensitive tree species from ambient
ozone concentrations and accounting for
the prevalence of those species within
the forest. As a way to quantify the risks
to particular plants from ground-level
ozone, scientists have developed ozoneexposure/tree-response functions by
exposing tree seedlings to different
ozone levels and measuring reductions
in growth as ‘‘biomass loss.’’ Typically,
seedlings are used because they are easy
to manipulate and measure their growth
loss from ozone pollution. The
mechanisms of susceptibility to ozone
within the leaves of seedlings and
mature trees are identical, and the
decreases predicted using the seedlings
104 Drevnick, P.E., D.E. Canfield, P.R. Gorski,
A.L.C. Shinneman, D.R. Engstrom, D.C.G. Muir,
G.R. Smith, P.J. Garrison, L.B. Cleckner, J.P. Hurley,
R.B. Noble, R.R. Otter, and J.T. Oris. 2007.
Deposition and cycling of sulfur controls mercury
accumulation in Isle Royale fish. Environmental
Science and Technology 41(21):7266–7272.
105 Munthe, J., R.A. Bodaly, B.A. Branfireun, C.T.
Driscoll, C.C. Gilmour, R. Harris, M. Horvat, M.
Lucotte, and O. Malm. 2007. Recovery of mercurycontaminated fisheries. AMBIO:A Journal of the
Human Environment 36:33–44.
106 Fox, S., Mickler, R.A. (Eds.). 1996. Impact of
Air Pollutants on Southern Pine Forests. Ecological
Studies. (Vol. 118, 513 pp.) New York: SpringerVerlag.
107 U.S. Environmental Protection Agency (U.S.
EPA). 2006. Air Quality Criteria for Ozone and
Related Photochemical Oxidants (Final). EPA/600/
R–05/004aF–cF. Washington, DC: U.S. EPA.
February. https://cfpub.epa.gov/ncea/CFM/
recordisplay.cfm?deid=149923.
108 De Steiguer, J., Pye, J., Love, C. 1990. Air
Pollution Damage to U.S. Forests. Journal of
Forestry, 88(8), 17–22.
109 Pye, J.M. 1988. Impact of ozone on the growth
and yield of trees: A review. Journal of
Environmental Quality, 17, 347–360.
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should be related to the decrease in
overall plant fitness for mature trees, but
the magnitude of the effect may be
higher or lower depending on the tree
species.110 In areas where certain ozonesensitive species dominate the forest
community, the biomass loss from
ozone can be significant. Significant
biomass loss can be defined as a more
than 2 percent annual biomass loss,
which would cause long-term ecological
harm, as the short-term negative effects
on seedlings compound to affect longterm forest health.111
Urban ornamentals are an additional
vegetation category likely to experience
some degree of negative effects
associated with exposure to ambient
ozone levels. Because ozone causes
visible foliar injury, the aesthetic value
of ornamentals (such as petunia,
geranium, and poinsettia) in urban
landscapes would be reduced. Sensitive
ornamental species would require more
frequent replacement and/or increased
maintenance (fertilizer or pesticide
application) to maintain the desired
appearance because of exposure to
ambient ozone.112 In addition, many
businesses rely on healthy-looking
vegetation for their livelihoods (e.g.,
horticulturalists, landscapers, Christmas
tree growers, farmers of leafy crops, etc.)
and a variety of ornamental species have
been listed as sensitive to ozone.113
D. Costs and Employment Impacts
1. Transport Rule Costs and
Employment Impacts
For the affected region, the projected
annual private incremental costs of the
rule to the power industry are $1.4
billion in 2012 and $0.8 billion in 2014.
These costs represent the private
compliance cost to the electric
generating industry of reducing NOX
and SO2 emissions to meet the
requirements set forth in the rule.
Estimates are in 2007 dollars.
In estimating the net benefits of
regulation, the appropriate cost measure
110 Chappelka, A.H., Samuelson, L.J. 1998.
Ambient ozone effects on forest trees of the eastern
United States: a review. New Phytologist, 139, 91–
108.
111 Heck, W.W. & Cowling, E.B. 1997. The need
for a long term cumulative secondary ozone
standard—an ecological perspective. Environmental
Management, January, 23–33.
112 U.S. Environmental Protection Agency (U.S.
EPA). 2007. Review of the National Ambient Air
Quality Standards for Ozone: Policy assessment of
scientific and technical information. Staff paper.
Office of Air Quality Planning and Standards. EPA–
452/R–07–007a. July. https://www.epa.gov/ttn/
naaqs/standards/ozone/data/2007_07_ozone_staff_
paper.pdf.
113 Abt Associates, Inc. 2005. U.S. EPA. Urban
ornamental plants: sensitivity to ozone and
potential economic losses. Memorandum to Bryan
Hubbell and Zachary Pekar.
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is ‘‘social costs.’’ Social costs represent
the welfare costs of the rule to society.
These costs do not consider transfer
payments (such as taxes) that are simply
redistributions of wealth. The social
costs of this rule are estimated to be
approximately $0.8 billion annually in
2014. Overall, the economic impacts of
the Transport Rule are modest in 2014,
particularly in light of the large benefits
($120 to $280 billion annually at a 3
percent discount rate and $110 to $250
billion annually at a 7 percent discount
rate) we expect, as shown in section
XII.A of this preamble. Ultimately, we
believe the electric power industry will
pass along most of the costs of the rule
to consumers, so that the costs of the
rule will largely fall upon the
consumers of electricity. For more
information on electricity price changes
that result from this final rule, refer to
section XII.H (Statement of Energy
Effects) later in this preamble.
For this rule, EPA analyzed the costs
using the Integrated Planning Model
(IPM). The IPM is a dynamic linear
programming model that can be used to
examine the economic impacts of air
pollution control policies for SO2 and
NOX throughout the contiguous United
States for the entire power system.
Documentation for IPM can be found in
the docket for this rulemaking or at
https://www.epa.gov/airmarkets/
progsregs/epa-ipm/.
EPA also included an analysis of
impacts of the final rule to industries
outside of the electric power sector by
using the Multi-Market Model. This
model is a partial equilibrium economic
impact model that includes 100 sectors
that cover energy, manufacturing, and
service applications and is designed to
capture the short-run effects associated
with an environmental regulation. This
model was used to estimate economic
impacts for the proposed MATS, and
the promulgated industrial boilers major
and area source standards and CISWI
standard.
We use the Multi-Market Model to
estimate the social costs of the final
rule. Using this model, we estimate the
social costs of the final rule to be
approximately $0.8 billion (2007
dollars), which is close to the
compliance costs. Documentation for
the Multi-Market Model can be found in
the RIA for this final rule.
Also note that as explained in section
V.B (Baseline for Pollution Transport
Analysis), the baseline used in this
analysis assumes no CAIR. As explained
in that section, EPA believes that this is
the most appropriate baseline to use for
purposes of determining whether an
upwind state has an impact on a
downwind monitoring site in violation
of section 110(a)(2)(D).
Although a stand-alone analysis of
employment impacts is not included in
a standard cost-benefit analysis, the
current economic climate has led to
heightened concerns about potential job
impacts. Such an analysis is of
particular concern in the current
economic climate as sustained periods
of excess unemployment may introduce
a wedge between observed (market)
wages and the social cost of labor. In
such conditions, the opportunity cost of
labor required by regulated sectors to
bring their facilities into compliance
with an environmental regulation may
be lower than it would be during a
period of full employment (particularly
if regulated industries employ otherwise
idled labor to design, fabricate, or install
the pollution control equipment
required under this rule). For that
reason, EPA also includes estimates of
job impacts associated with the final
rule. EPA presents an estimate of shortterm employment opportunities as a
result of increased demand for pollution
control equipment. Overall, the results
suggest that the final rule could support
a net increase of roughly 2,250 job-years
in direct employment in 2014.
The basic approach to estimate these
employment impacts involved using
projections from IPM from the final rule
analysis such as the amount of capacity
that will be retrofit with control
technologies, for various energy market
implications, along with data on labor
and resource needs of new pollution
controls and labor productivity from
secondary sources, to estimate
employment impacts for 2014. This
analysis was also applied for the
proposed MATS. For more information,
refer to Appendix D of the RIA for the
final Transport Rule.’’
EPA relied on Morgenstern, et al.
(2002), a study that is a basis for
employment impacts estimated for the
final industrial boiler major and area
source rules and CISWI standard, and
the proposed MATS. The Morgenstern
study identifies three economic
mechanisms by which pollution
abatement activities can indirectly
influence jobs: (1) Higher production
costs raise market prices, higher prices
reduce consumption, and employment
within an industry falls (‘‘demand
effect’’); (2) pollution abatement
activities require additional labor
services to produce the same level of
output (‘‘cost effect’’); and (3) post
regulation production technologies may
be more or less labor intensive (i.e.,
more/less labor is required per dollar of
output) (‘‘factor-shift effect’’).
Using plant-level Census information
between the years 1979 and 1991,
Morgenstern, et al., estimate the size of
each effect for four polluting and
regulated industries (petroleum, plastic
material, pulp and paper, and steel). On
average across the four industries, each
additional $1 million spending on
pollution abatement results in a small
net increase of 1.6 jobs; however, the
estimated effect is not statistically
significant. As a result, the authors
conclude that increases in pollution
abatement expenditures do not
necessarily cause economically
significant employment changes. The
conclusion is similar to Berman and Bui
(2001), who found that increased air
quality regulation in Los Angeles did
not cause large employment changes.
For more information, please refer to the
RIA for this final rule.
The ranges of job effects calculated
using the Morgenstern, et al., approach
are listed in Table VIII.D–1.
TABLE VIII.D–1—RANGE OF JOB EFFECTS FOR THE ELECTRICITY SECTOR
[Estimates using Morgenstern, et al. (2002)]
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Demand effect
Change in Full-Time Jobs per Million Dollars of
Environmental Expenditure a.
Standard Error .........................................................
EPA Estimate for Final Rule b .................................
Cost effect
Factor shift
effect
¥3.56 ......................
2.42 ..........................
2.68 ..........................
1.55.
2.03 ..........................
+ 200 to ¥3,000 .....
0.83 ..........................
+ 400 to 2,000 .........
1.35 ..........................
0 to 2,000 ................
2.24.
¥1,000 to + 3,000.
a Expressed
Net effect
in 1987 dollars. See footnote a of Table 8–3 in the RIA for the inflation adjustment factor used in the analysis.
to the 2007 Economic Census, the electric power generation, transmission, and distribution sector (NAICS 2211) had approximately 510,000 paid employees.
b According
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EPA recognizes there may be other job
effects which are not considered in the
Morgenstern, et al., study. Although
EPA has considered some economywide changes in industry output as
shown earlier with the Multi-Market
model, we do not have sufficient
information to quantify other associated
job effects associated with this rule.
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2. End-Use Energy Efficiency
EPA believes that achievement of
energy efficiency (EE) improvements in
homes, buildings, and industry is an
important component of achieving
emission reductions from the power
sector while minimizing associated
compliance costs. By reducing
electricity demand, energy efficiency
avoids emissions of all pollutants
associated with electricity generation,
including emissions of NOX and SO2
targeted by this final rule, and reduces
the need for investments in EGU
emission control technologies in order
to meet emission reduction
requirements. Moreover, energy
efficiency can often be implemented at
a lower cost than traditional control
technologies.
EPA recognizes that significant
opportunities remain for energy
efficiency improvements in businesses,
homes, and industry. However, there are
several informational and market
barriers that limit investment in costeffective energy efficient practices.
Several federal programs authorized
under the CAA, including ENERGY
STAR, are designed to address these
barriers.
Congress, EPA, and states have all
recognized the value of incorporating
energy efficiency into air regulatory
programs. Several allowance-based
programs—including the Acid Rain
Program, EPA’s NOX Budget Trading
program, and the Regional Greenhouse
Gas Initiative (an effort of 10 states from
the Northeast and Mid-Atlantic regions)
– have provided mechanisms for
rewarding energy efficiency through
either the award of allowances, typically
through the use of a fixed set-aside pool,
or the use of revenues obtained through
the auction of allowances. The emission
caps established by these programs are
unaffected by this approach. However,
to the extent electricity demand
reductions are realized, compliance
costs are reduced. In addition to these
allowance-based programs, EPA has also
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provided guidance 114 concerning the
recognition, in SIPs, of emission
reduction benefits of energy efficiency
and has approved the inclusion of EE
measures in individual SIPs.115
While all remedy options considered
in the proposed rule would have lead to
an increase in the relative costeffectiveness of EE investments by
internalizing environmental costs
associated with emission of these
pollutants, EPA took comment on
whether EPA has authority, and
whether it would be appropriate for
EPA, to consider EE in developing the
allowance allocation methodology and
to consider other approaches for
encouraging EE in the Transport Rule.
Some commenters suggested that EPA
has authority to consider EE in
developing the allocation methodology.
Other commenters do not believe EPA
has the authority to consider EE. Some
commenters suggested that EPA should
establish an EE set-aside provision.
Other commenters suggested that EPA
should allow, and help, states to
establish EE set-asides as states
transition from Transport Rule FIPs to
SIPs. EPA believes that, while EE setasides can be effective at encouraging
incremental investments in EE, EE setasides are more likely to be practically
and effectively implemented at the state
level. Establishing EE set-asides in the
allowance allocation provisions in the
final rule would not allow for the
tailoring of the set-asides to the unique
characteristics of individual states and
would not build on the existing EE
program delivery infrastructure that
many states already possess. Instead of
establishing EPA-administered EE setasides in the final rule, EPA is clarifying
that it allows and supports EE set-asides
(including auction-based approaches) in
abbreviated or full SIPs that states may
submit, as provided in the final rule.
Under this approach states have the
ability to implement EE set-asides
tailored to their state circumstances, if
they choose. EPA anticipates providing
114 U.S. EPA. 2004. Guidance on State
Implementation Plan (SIP) Credits for Emission
Reductions from Electric-Sector Energy Efficiency
and Renewable Energy Measures.
https://www.epa.gov/ttn/oarpg/t1/memoranda/
ereseerem_gd.pdf.
115 Metropolitan Washington Council of
Governments developed a regional air quality plan
for the eight-hour ozone standard for the DC Region
nonattainment area that included an EE measure.
The plan was adopted by Virginia, Maryland, and
the District of Columbia and the respective ozone
SIPs were approved by the EPA regions in 2007.
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additional information in the future for
states on EE set-asides, as needed.116
As discussed elsewhere in this
preamble, the final rule provides for
submission and approval of abbreviated
and full SIPs providing for continued
state participation in the Transport Rule
trading programs, and adopting
alternative allowance allocation
methodologies (which may include EE
set-asides) to the allocation
methodologies adopted in the FIPs.
While the final rule establishes certain
requirements for approval of any such
alternative allocation methodology, the
final rule provides states flexibility to
create state-implemented EE set-asides.
IX. Related Programs and the Transport
Rule
A. Transition From the Clean Air
Interstate Rule
1. Key Differences Between the
Transport Rule and CAIR
The Transport Rule replaces CAIR
and its associated trading programs.
There are a number of differences
between implementation of the
Transport Rule and implementation of
CAIR. This section describes key
implementation differences including
differences in states covered,
compliance deadlines, applicability,
structure of the remedy, provisions for
early reductions, and provisions for
SIPs. The next section discusses the
transition from CAIR to the Transport
Rule.
States covered. The states covered by
the Transport Rule differ somewhat
from states covered by CAIR. This
section summarizes differences in state
coverage. EPA’s approach to determine
states covered by the Transport Rule is
discussed in sections V and VI of this
preamble.
The Transport Rule’s SO2 and annual
NOX requirements apply to covered
sources in the 23 states listed in Table
III–1 in section III of this preamble.
CAIR’s SO2 and annual NOX
requirements applied to covered sources
in 25 states. There are many states in
common between the Transport Rule
and CAIR SO2 and annual NOX
programs. The differences are
summarized in Table IX.A–1.
116 Because the question of EPA authority to
create EE set-asides in the FIPs would be best
addressed in the context of actual FIP provisions for
EPA-created EE set-asides and EPA is, for other
reasons, not adopting such provisions in the final
rule, EPA is not addressing in the final rule the
question of EPA’s authority.
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TABLE IX.A–1—DIFFERENCES IN SO2 AND ANNUAL NOX STATE COVERAGE BETWEEN THE TRANSPORT RULE AND CAIR
State
Transport rule
SO2 and annual NOX
programs
Kansas ........................................................................................................................................................................
Minnesota ...................................................................................................................................................................
Nebraska .....................................................................................................................................................................
Delaware .....................................................................................................................................................................
District of Columbia ....................................................................................................................................................
Florida .........................................................................................................................................................................
Louisiana .....................................................................................................................................................................
Mississippi ...................................................................................................................................................................
Yes ...............
Yes ...............
Yes ...............
No ................
No ................
No ................
No ................
No ................
The Transport Rule’s ozone-season
NOX requirements apply to covered
sources in the 20 states listed in Table
III–1 in section III of this preamble,
while CAIR’s ozone-season NOX
requirements applied to 26 states. There
are many states in common between the
Transport Rule and CAIR ozone-season
CAIR SO2
and annual
NOX programs
No.
No.
No.
Yes.
Yes.
Yes.
Yes.
Yes.
NOX programs. The differences are
summarized in Table IX.A–2.
TABLE IX.A–2—DIFFERENCES IN OZONE-SEASON NOX STATE COVERAGE BETWEEN THE TRANSPORT RULE AND CAIR
Transport rule
ozone-season
NOX program
CAIR ozoneseason NOX
program
Georgia .......................................................................................................................................................................
Texas ..........................................................................................................................................................................
Connecticut .................................................................................................................................................................
Delaware .....................................................................................................................................................................
District of Columbia ....................................................................................................................................................
Iowa ............................................................................................................................................................................
Massachusetts ............................................................................................................................................................
Michigan ......................................................................................................................................................................
Missouri .......................................................................................................................................................................
Wisconsin ....................................................................................................................................................................
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State
Yes ...............
Yes ...............
No ................
No ................
No ................
No ................
No ................
No ................
No ................
No ................
No.
No.
Yes.
Yes.
Yes.
Yes.
Yes.
Yes.
Yes.
Yes.
In addition, EPA is proposing a
supplemental notice to apply Transport
Rule ozone-season requirements to the
states of Iowa, Kansas, Michigan,
Missouri, Oklahoma, and Wisconsin, as
discussed in section III of this preamble.
The transition from CAIR to the
Transport Rule is discussed in section
IX.A.2 and SIPs are discussed in section
X of this preamble.
Compliance deadlines. The Transport
Rule reduction requirements commence
January 1, 2012 for annual NOX and SO2
requirements and May 1, 2012 for
ozone-season NOX requirements. More
stringent SO2 reduction requirements
commence January 1, 2014 for Group 1
states.
In contrast, the first phase of CAIR
NOX reductions commenced January 1,
2009 for annual NOX requirements and
May 1, 2009 for ozone-season NOX
requirements. On January 1, 2010, the
first phase of CAIR SO2 requirements
commenced. However, in anticipation
of CAIR, SO2 reductions actually started
as early as 2006 because of the incentive
to reduce emissions and bank Title IV
Acid Rain Program SO2 allowances for
use when their value would increase
under CAIR in 2010 and later. The
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second phase of CAIR reductions would
have (if not replaced by the Transport
Rule) commenced January 1, 2015 for
annual NOX and SO2 requirements, and
May 1, 2015 for ozone-season NOX
requirements.
Applicability. Except for the changes
to the states covered, the general
applicability provisions of the final
Transport Rule trading programs are
essentially the same as the CAIR general
applicability provisions, with a few
exceptions.
First, the final Transport Rule does
not allow any non-covered units to opt
into the trading programs, for the
reasons discussed in section VII.B of
this preamble. In contrast, under CAIR,
through SIPs, the states could elect to
allow boilers, combustion turbines, and
other combustion devices to opt into the
CAIR trading programs under opt-in
provisions specified by EPA.
Second, the Transport Rule FIPs’
ozone-season NOX trading program
applicability provisions do not cover
NOX SIP Call small EGUs and non-EGUs
that a number of CAIR states brought
into the CAIR ozone-season NOX trading
program. The Transport Rule does allow
any state in the ozone-season NOX
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program, through SIPs, to expand the
applicability of the Transport Rule
ozone-season NOX trading program to
cover small EGUs. However, the
Transport Rule does not allow states to
expand the applicability to cover NOX
SIP Call non-EGUs, for the reasons
discussed elsewhere in this preamble.
In contrast, in the CAIR trading
programs, a NOX SIP Call state could
expand the applicability of the CAIR
ozone-season NOX trading program in
the state in order to include all units
subject to the NOX Budget Trading
Program under the NOX SIP Call. A
number of states chose to expand the
CAIR ozone-season NOX trading
program applicability in this way. The
transition from CAIR to the Transport
Rule is discussed in section IX.A.2 and
SIPs are discussed in section X of this
preamble.
Structure of the remedy. The CAIR
FIPs (and CAIR model trading rules
adopted by a number of states in their
CAIR SIPs) implemented reductions
through SO2, annual NOX, and ozoneseason NOX interstate emission trading
programs covering primarily large
EGUs. The owners and operators of a
covered source could buy allowances
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from or sell allowances to other covered
sources (or other market participants)
and were required to surrender
allowances equal to the source’s
emissions for each compliance period.
CAIR’s trading programs did not impose
limitations on the aggregate emissions
from covered units within any covered
state.
The Transport Rule FIPs will also
achieve the required reductions through
SO2, annual NOX, and ozone-season
NOX interstate trading programs.
However, in contrast to CAIR and for
the reasons discussed in section VII of
this preamble, the Transport Rule FIPs
include assurance provisions
specifically designed to ensure that no
state’s emissions will exceed that state’s
emission budget plus the variability
limit, i.e., the state’s assurance level.
Another difference in the remedy
structure is in the design of the SO2
trading programs. In CAIR all of the
states required to reduce SO2 emissions
were grouped together in one SO2
trading program with no restriction on
the use of SO2 allowances from any state
in the program by any source in the
program. In contrast, and for the reasons
discussed in section VI of this preamble,
the Transport Rule divides states
required to reduce SO2 emissions into
two groups with emission reduction
requirements of different stringency
starting in 2014 (SO2 Group 1, whose
reduction requirements become more
stringent starting in 2014, and SO2
Group 2, whose reduction requirements
in 2014 do not change). A covered
source may only use for compliance—
with the requirements to hold
allowances covering emissions and, if
applicable, to surrender allowances
under the assurance provisions—an SO2
allowance issued for the SO2 Group in
which the source’s state is included. In
other words, an SO2 Group 1 source
may only use a SO2 Group 1 allowance
for compliance, and likewise an SO2
Group 2 source may only use a SO2
Group 2 allowance for compliance.
Provisions for early reductions. CAIR
included provisions for covered sources
to make early reductions prior to the
start of CAIR’s SO2 and NOX trading
programs, bank emission allowances,
and carry banked allowances into its
trading programs. In contrast, the
Transport Rule does not include
provisions for covered sources to carry
over any allowances (i.e., Title IV SO2
allowances or CAIR annual or ozoneseason NOX allowances) into the
Transport Rule trading programs. EPA’s
reasons for not allowing the use of
banked Title IV SO2 allowances or CAIR
annual or ozone-season NOX allowances
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in the Transport Rule trading programs
are discussed in the next section.
Provisions for SIPs. The following is
a summary of the key differences
between the Transport Rule and CAIR
provisions for SIPs. A more detailed
discussion of Transport Rule SIPs is in
section X of this preamble.
The SIP provisions in the Transport
Rule and CAIR are very similar. Both
include provisions that allow states to
submit SIP revisions (referred to as full
SIPs) that replace an applicable FIP
trading program with a comparable SIP
trading program that has certain limited
differences from the FIP trading
program. Similarly, both rules include
provisions that allow states to submit
SIP revisions (referred to as abbreviated
SIPs) that may modify certain limited
provisions in the FIP trading program,
which remain in place. Inclusion of this
provision in the Transport Rule allows
a state to modify certain elements of a
Transport Rule FIP trading program in
order to better meet the needs of the
state. Both the Transport Rule and CAIR
allow full or abbreviated SIPs that
involve one or more applicable FIP
trading programs. However, there are a
few differences.
In particular, under the Transport
Rule, states may submit SIP revisions
under which the state determines
allocations for the applicable trading
program using either full or abbreviated
SIP revisions. States could submit
similar revisions under CAIR. Under the
Transport Rule, the state may use the
same allocation methodology as that
currently used in the Transport Rule FIP
trading program or some other
allocation methodology. However, the
Transport Rule specifies certain
requirements that must be met
concerning, for example, the timing of
such allocation determinations, and
expressly allows allowance auctions to
be used. CAIR did not include similar
provisions. Further, the SIP submission
deadlines, allocation submission, and
allocation recordation dates are different
between the Transport Rule and CAIR.
The Transport Rule SIP submission
deadlines and allocation recordation
dates are discussed in section X of this
preamble.
In addition, both the Transport Rule
and CAIR include provisions that allow
states to submit SIP revisions under
which the state expands the general
applicability provisions of the ozoneseason NOX trading programs to cover
certain units subject to the NOX SIP
Call. However, for the reasons discussed
elsewhere in this preamble, this
flexibility is more limited in the
Transport Rule than it was in CAIR.
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48321
While CAIR allowed states to adopt,
through full or abbreviated SIPs, opt-in
provisions, the Transport Rule does not
allow for opt-in provisions. The reasons
for this are discussed in section VII.B of
this preamble.
Finally, neither full nor abbreviated
SIPs can replace FIP provisions that
apply to units in Indian country within
the borders of a state. For example, the
FIPs include, for states within whose
borders Indian country is located, an
Indian country new unit set-aside. For
states not having Indian country within
their borders, abbreviated SIPs are
limited to replacing the allowance
allocation provisions of the FIPs for the
state involved and may replace some or
all of those provisions. However, for
states having Indian country within
their borders, abbreviated SIPs cannot
replace the FIP provisions for the Indian
country new unit set-aside. Similarly,
for states not having Indian country, full
SIPs can replace an entire FIP, but, in
doing so, can only change the allowance
allocation provisions. For states having
Indian country, full SIPs can replace the
FIPs except for the Indian country new
unit set-aside provisions, which will
remain under the applicable FIPs, and,
like the abbreviated SIPs, can only
change the allowance allocation
provisions that are replaced.
Details of the Transport Rule
provisions for abbreviated and full SIP
revisions, including deadlines for
submission to EPA, are discussed in
section X of this preamble.
2. Transition From the Clean Air
Interstate Rule to the Transport Rule
The Transport Rule replaces CAIR
and its associated trading programs.
This section elaborates on areas of
transition from CAIR to the Transport
Rule.
a. Sunsetting of CAIR, CAIR SIPs, and
CAIR FIPs
The proposal explained that, for
control periods in 2012 and thereafter,
CAIR, CAIR SIPs, and CAIR FIPs would
be replaced entirely by the Transport
Rule provisions. The proposal outlined
implementation of the sunsetting of
CAIR and CAIR FIPs, through revisions
to CAIR, §§ 51.123 and 51.124, and the
CAIR FIPs, §§ 52.35 and 52.36. For the
control period in these years, the CAIR
trading programs would not continue,
and the Administrator would not carry
out any of the functions established for
the Administrator in the CAIR model
trading rule, the CAIR FIPs, or any state
trading programs approved under CAIR.
Offset and automatic penalty provisions
under CAIR would not apply to excess
emissions for 2011 control periods.
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Also discussed were the processes for
modifying provisions in Part 52
reflecting state-specific CAIR SIP and
CAIR FIP requirements, which would
vary depending on whether a state has
an approved CAIR SIP or a CAIR FIP.
The proposal further explained that
sources in some states covered by CAIR
or the CAIR FIPs would not be subject
to the Transport Rule and that to the
extent that CAIR reductions were
needed or relied upon to satisfy other
SIP requirements, states might need to
find alternative ways to satisfy
requirements for their SIPs.
EPA is finalizing regulatory changes
to sunset CAIR and the CAIR FIPs. The
final rule revises the general CAIR and
CAIR FIP provisions in Parts 51 and 52
applicable to all CAIR states. For control
periods in 2012 and thereafter, the
Administrator rescinds the
determination that states must meet SIP
requirements under CAIR, and the
requirements of the CAIR FIPs are not
applicable. Further, with regard to these
control periods, the Administrator will
no longer carry out any of the functions
established for the Administrator in the
CAIR model trading rule, the CAIR FIPs,
or any state trading programs approved
under CAIR with the exception of
enforcing the provisions for the
previous control periods, if necessary.
For the reasons discussed in the
proposed rule preamble (75 FR 45337),
CAIR allowances allocated for these
control periods cannot be used in any
CAIR trading program and, as discussed
below, in any Transport Rule trading
program. Specifically, for the reasons
discussed in the proposed rule, offset
and automatic allowance penalty
provisions in the CAIR trading programs
will not be applied to 2011 control
period excess emissions, which will
remain subject to discretionary civil
penalties under CAA section 113. EPA
still retains all enforcement options for
excess emissions during the 2011
control period. CAIR allowances
allocated for 2012 and thereafter are not
usable in any CAIR or Transport Rule
trading program. In light of that fact, in
order to prevent any confusion by
owners and operators and other
members of the public concerning the
status of such allowances, the final rule
provides that, within 90 days after
publication of the final Transport Rule,
the Administrator will remove post2011 CAIR annual NOX and ozoneseason allowances from the Allowance
Tracking System.
The CAIR SO2 trading program, of
course, uses Acid Rain allowances,
which will remain in the Allowance
Tracking System because they were
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created by CAA Title IV and continue to
be usable in the Acid Rain Program.
The final rule also adopts the
discussion in the proposed rule
concerning state-specific Part 52
provisions concerning CAIR (75 FR
45337–38). With regard to Part 52
provisions reflecting EPA’s adoption of
ongoing CAIR FIPs for some individual
states, the final rule revises the CAIR
FIP provisions to make them
inapplicable to control periods in 2012
and thereafter and to require the
Administrator to remove from the
Allowance Tracking System, CAIR
allowances for these control periods.
The final, state-specific CAIR FIP
provisions in Part 52 essentially echo
the language in the final, general CAIR
provisions in Part 52 discussed above.
In making the CAIR FIP provisions
inapplicable to control periods in 2012
and thereafter, the final, state-specific
provisions sunset the applicable CAIR
FIP trading programs whether or not the
CAIR FIPs were revised by approved,
abbreviated CAIR SIPs. (Under CAIR,
abbreviated CAIR SIPs were adopted by
certain states so that states, rather than
EPA, made NOX allowance allocations.)
Consequently, states with approved,
abbreviated CAIR SIPs will not need to
revise their abbreviated CAIR SIPs in
order to sunset the CAIR trading
programs to which these abbreviated
SIPs applied. Thus, although such
abbreviated SIPs may remain in the state
SIPs, they will have no force and effect,
once the CAIR FIPs sunset.
With regard to Part 52 provisions
reflecting EPA’s approval of full CAIR
SIPs submitted to EPA by many
individual states, the Court’s North
Carolina decision essentially overrides
these Agency approvals of individual
CAIR SIPs. (Under CAIR, full CAIR SIPs
were adopted by certain states to replace
CAIR FIPs and continue participation
through the CAIR SIPs in the CAIR
trading programs.) The Court found
CAIR to be illegal and only allowed it
to remain in effect temporarily. For this
reason, the CAIR SIPs though approved,
can have no force and effect once CAIR
is replaced by this rule. For this reason,
although the proposed rule indicated
that states would need to submit SIP
revisions to, among other things, make
the CAIR SIPs inapplicable to control
periods after 2011, the final rule does
not require states to take any actions to
revise their full or abbreviated CAIR
SIPs. For states covered by CAIR or
CAIR FIPs that are not subject to the
Transport Rule and have relied on CAIR
reductions to satisfy other SIP
requirements, EPA will discuss with
states alternative ways to satisfy
requirements for those SIP
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requirements, e.g., through intrastate
cap and trade programs that require the
level of reductions on which the state
has recently relied.
b. NOX SIP Call Units
The NOX Budget Trading program
was used by states to reduce ozoneseason NOX emissions from EGUs and
large non-EGUs under NOX SIP Call
requirements. The program started in
2003 and ended in 2008. Under CAIR,
a state subject to the NOX SIP Call was
allowed to expand the applicability of
the CAIR ozone-season NOX trading
program in the state in order to include
all units subject to the NOX Budget
Trading Program under the NOX SIP
Call and thereby to continue to meet the
state’s NOX SIP Call requirements.
Fourteen states chose to expand the
CAIR ozone-season NOX applicability in
this way, while six states chose not to
expand the applicability and instead to
meet their NOX SIP Call obligations in
other ways. EPA proposed to not allow
this expansion in applicability for the
Transport Rule, primarily because these
sources as a group did not actually
reduce emissions for the NOX Budget
Trading Program or CAIR. EPA took
comment on the proposed approach.
Several commenters generally
advocated allowing, at state discretion,
all NOX Budget Trading Program units
to be regulated under the Transport Rule
ozone-season NOX trading program.
Some also questioned how states would
otherwise satisfy NOX SIP Call
requirements for these units. Some
commenters argued that some units did
in fact make emission reductions in the
NOX Budget Trading Program, but did
not provide information on specific
units.
The final rule provides states an
option to expand the general
applicability provisions of the Transport
Rule ozone-season NOX trading program
to cover small EGUs, but not other units
in the NOX SIP Call. Specifically,
consistent with the comments, EPA
determined that it is appropriate to
allow states to expand the applicability
of the Transport Rule ozone-season NOX
trading program to include units serving
a generator with a nameplate capacity
equal to or greater than 15 MWe
producing electricity for sale. This will
allow states with NOX SIP Call
obligations to meet those requirements
with respect to these small EGUs. These
units can be brought into the program
through abbreviated or full Transport
Rule SIPs. However, if a state chooses to
expand the general applicability
provisions, the state Transport Rule
ozone-season NOX budget cannot be
increased. EPA believes that the level of
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emissions from small EGUs is
sufficiently small that the existing
Transport Rule state budget can
accommodate these units. This is
consistent with the approach taken in
the NOX Budget Trading Program,
where the states that added these small
EGUs did not increase their NOX SIP
Call EGU budgets. This also removes
concern (expressed in the proposed
rule) that increasing state budgets in the
Transport Rule ozone-season NOX
trading program, as part of the
expansion of the applicability
provisions to include small EGUs,
would jeopardize elimination of a state’s
significant contribution to
nonattainment and interference with
maintenance.
With regard to large non-EGUs that
were included in the NOX Budget
Trading Program (the remainder of the
sources in the NOX Budget Trading
Program), the final Transport Rule, like
the proposed rule, does not allow
expansion of the general applicability
provisions for the ozone-season NOX
trading program to include such units.
As explained in the proposed rule (75
FR 43340), while some of these units
may have installed controls around the
start of the NOX Budget Trading
Program, EPA analysis shows that, as a
group, these units did not collectively
reduce emissions, their current emission
rates are nearly identical to their
emission rates before the start of the
NOX Budget Trading Program, and their
allocations are about twice their
emissions, with the result that the
excess allocations were sold to covered
EGUs.117 Moreover, EPA believes that
there are little or no emission reductions
available by non-EGUs at the cost
thresholds used in the final rule and so
no basis for developing non-EGUs state
budgets reflecting the elimination of
significant contribution to
nonattainment and interference with
maintenance. For these reasons, the
final rule allows states to expand the
ozone-season NOX trading program to
cover small EGUs that were in the NOX
Budget Trading Program, but not to
cover large non-EGUs that were in that
program. As explained in the proposed
rule, if a state were to do so, emissions
from these units could jeopardize
elimination of the state’s significant
contribution to nonattainment or
interference with maintenance. See 75
FR 45340. For states that relied on large
117 Although the proposed rule discussed the EPA
analysis in the context of considering the treatment
of both small EGUs and large non-EGUs from the
NOX Budget Trading Program, the analysis actually
addresses, and draws conclusions about emission
reductions, emission rates, and allowance
allocations concerning only large non-EGUs.
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non-EGUs for emission reductions
required by the NOX SIP Call, EPA will
assist in identifying ways to ensure
continued, future compliance with the
NOX SIP Call requirements.
c. Early Reduction Provisions
Substantial emission reductions have
occurred as a result of previous
emission trading programs, under both
Title IV and CAIR. This has lead to
substantial ‘‘banks’’ of allowances (i.e.,
holdings of unused allowances allocated
for years before the programs sunset) in
each of the CAIR programs. In the
proposal, EPA requested comment on
whether to allow banked CAIR
allowances to be used in the Transport
Rule trading programs. EPA recognizes
the importance of continuity in
emission trading programs as a general
principle. However, for the reasons
explained below, EPA has decided not
to allow banked CAIR allowances to be
used in any of the Transport Rule
trading programs. (1) SO2 Allowance
Bank
The bank of Title IV allowances was
more than 12 million tons at the end of
2009. This bank is the result of emission
reductions under the Title IV Acid Rain
Program. Under the CAIR SO2 trading
program, EPA allowed banked (as well
as future year) Title IV allowances to be
used in the CAIR SO2 trading program—
in lieu of being used in the Acid Rain
Program—for compliance with the
requirement to hold allowances
covering SO2 emissions. This approach
encouraged early reductions for the
CAIR SO2 trading program, but was held
to be unlawful in North Carolina.
In the proposed rule, EPA took
comment on whether sources should be
allowed to use banked Title IV
allowances in the Transport Rule SO2
program. EPA proposed to not allow the
use of Title IV allowances either as the
basis for allocating Transport Rule SO2
allowances or directly for compliance
with allowance-holding requirements,
in part, because EPA was concerned that
those approaches would be perceived as
inconsistent with the requirements of
CAA section 110(a)(2)(D)(i)(I) as
interpreted by the Court in North
Carolina. See 75 FR 45338–39.
A number of commenters advocated
that EPA recognize Title IV allowance
holdings in the Transport Rule, either
by allowing full or limited carryover of
the allowances or by allocating all or a
portion of the Transport Rule SO2
allowances based on Title IV allowance
holdings. Other commenters agreed
with EPA’s assessment that allowing
Title IV allowance carryover in the
Transport Rule is inconsistent with
North Carolina and that any linkage of
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48323
Transport Rule allocations with Title IV
allowance holdings would carry
unnecessary, significant legal risk.
Therefore, for the reasons explained
above and in the proposal, EPA has
decided not to permit sources to use
Title IV allowances for compliance with
the Transport Rule SO2 trading
programs.
In addition, unlike CAIR, in the
Transport Rule, EPA decided not to base
allocation of Transport Rule SO2
allowances on the specific distribution
of existing Title IV allowances. Title IV
allowances continue, of course, to be
usable for compliance in the Acid Rain
Program.118
(2) NOX Allowance Banks
In the proposed rule, EPA estimated
that the CAIR ozone-season NOX bank
would contain over 600,000 allowances
and the CAIR annual NOX bank would
contain about 720,000 allowances after
completion of true-up of allowance
holdings and emissions for 2011. EPA
considered the alternatives of allowing
or not allowing pre-2012 CAIR NOX
allowances and CAIR ozone-season NOX
allowances to be used in the Transport
Rule NOX trading programs.
EPA also described and requested
comment on several possible
approaches for handling banked pre2012 CAIR NOX allowances in the
Transport Rule NOX trading programs
and the pros and cons of each (75 FR
45339):
• Allow all such banked CAIR
allowances to be brought into the
Transport Rule NOX programs, make the
assurance provisions effective starting
in 2012, and rely on the assurance
provisions to ensure that each state
continues to eliminate all of its
significant contribution to
nonattainment and interference with
maintenance;
• Allow only a limited amount of
banked pre-2012 CAIR allowances to be
brought into the Transport Rule NOX
programs;
• Factor the bank into the calculation
of state NOX budgets by reducing the
state NOX budgets to take account of the
banked pre-2012 CAIR allowances; and
• Do not allow the use of any banked
pre-2012 CAIR allowances in the
Transport Rule NOX programs.
EPA proposed the last of these
approaches and requested comment on
all of the described approaches or
suggestions on other ways to handle
banked pre-2012 CAIR allowances in
the Transport Rule NOX programs.
118 The Title IV allowance bank is expected to be
about 14 million tons at the beginning of 2012.
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• Many commenters advocated
allowing the carryover of CAIR NOX
allowances to the Transport Rule.
Reasons given included: preservation of
early reduction investments; need for
market continuity; increased flexibility
during program start up and early years
of the programs; preservation of the
credibility of, and certainty under,
trading approaches; and the lack of a
prohibition in North Carolina of
carryover of CAIR NOX allowances.
Commenters also suggested that
surrender ratios be used to limit the
amount, and negative effects, of a
carryover.
• Many other commenters were
against allowing CAIR NOX allowance
carryover into the Transport Rule.
Reasons given included: unnecessary,
significant legal risk; concerns about the
efficacy of the Transport Rule if state
budgets are supplemented by a
carryover; and differences in the nature
of the programs (the NOX Budget
Trading Program, which addressed the
1-hour ozone NAAQS, and the CAIR
ozone-season NOX trading program,
which addressed the 1997 8-hour ozone
NAAQS and was reversed in North
Carolina) under which the allowances
were banked, and the Transport Rule
ozone-season NOX trading program,
which addresses the 1997 8-hour ozone
NAAQS.
For the reasons explained below, after
evaluating all comments on this issue,
EPA decided not to allow the use of
CAIR NOX allowances in the Transport
Rule NOX trading programs. EPA
reevaluated the estimated size of the
potential carryover (allowances that will
remain unused in the CAIR programs at
the end of 2011 compliance periods),
taking into account 2010 emissions.
EPA estimates that more than 440,000
CAIR ozone-season NOX allowances
will remain and that more than 460,000
CAIR annual NOX allowances will
remain at the end of the 2011
compliance periods. EPA considered
whether to allow these CAIR ozoneseason NOX and CAIR annual NOX
allowances to be used in the Transport
Rule NOX trading programs. The CAIR
ozone-season NOX allowances expected
to remain unused represent nearly
three-quarters of aggregate state ozoneseason NOX budgets 119 in a single year
under the final Transport Rule. The
allowances expected to remain unused
in the annual NOX program represent
119 This analysis is for all states identified to be
contributing significantly to nonattainment or
interfering with maintenance. When the analysis is
conducted using the aggregate state budgets for only
those states for which we are finalizing ozone
season requirements in this rule, the percentage
increases.
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more than one-third of aggregate state
annual NOX budgets in a single year
under the Transport Rule. As discussed
in the proposal, if these allowances
were carried over in addition to the
Transport Rule state budgets, EPA could
not be assured that significant
contribution to nonattainment or
interference with maintenance would be
eliminated. EPA therefore rejects any
approach under which all banked CAIR
NOX allowances would be added to the
Transport Rule trading programs on top
of each state’s annual NOX and/or
ozone-season NOX budgets.
In response to public comments, EPA
considered whether the Transport Rule
trading programs should allow some
form of exchange of banked CAIR
annual NOX and ozone-season
allowances for new Transport Rule NOX
allowances within each state’s annual
NOX and/or ozone-season budgets,
respectively. However, EPA believes
that this type of approach carries
substantial legal and technical
problems. First, the state-by-state
distribution of CAIR NOX allowances
resulted from the methodology applied
by EPA in CAIR of using fuel factors to
set the total amounts of allowance
allocations in each state (i.e., the state
NOX budgets). The CAIR NOX allowance
banks therefore are—at least in part—
the result of this methodology, which
was reversed in North Carolina. See
North Carolina, 531 F.3d at 918–22.
Thus, EPA did not use fuel factors in
developing the Transport Rule state
budgets. However, EPA is concerned
that the distribution of some or all
Transport Rule NOX allowances through
exchanges of banked CAIR NOX
allowances for Transport Rule NOX
allowances would blur the bright line
between the methodology used for
setting budgets in the Transport Rule
and the methodology used for setting
budgets in CAIR that was rejected by the
Court. At least to some extent, the
parties that were advantaged under
EPA’s budget-setting methodology in
CAIR would continue to have an
advantage under the Transport Rule by
receiving more Transport Rule NOX
allowances. EPA therefore believes that
allowing exchange of banked CAIR NOX
allowances for Transport Rule NOX
allowances carries significant legal risk.
Second, establishing a procedure for
exchanging banked CAIR NOX
allowances for Transport Rule NOX
allowances within each state’s budget
would mean that Transport Rule NOX
allowances could not be allocated until
after completion of the process for
determining compliance with
allowance-holding requirements for
2011 in the CAIR NOX trading programs.
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This process cannot begin until after the
allowance transfer deadline for the 2011
control periods (i.e., March 1, 2012 for
the CAIR annual NOX program and
November 1, 2011 for the CAIR ozoneseason NOX program) and will not likely
be completed until mid-2012. At that
time, EPA could begin the procedure of
implementing, state-by-state, the
exchanges of the remaining CAIR NOX
allowance banks held by parties (owners
and operators, brokers, and other
entities) for some or all of the
allowances in the state NOX budgets for
2012. The portion of each state budget
that would be used up by such
exchanges would likely vary from state
to state. The resulting delay, and
uncertainty about the unit-by-unit
amounts, of Transport Rule NOX
allowance allocations for 2012 would
undermine Transport Rule allowance
market liquidity, significantly disrupt
planning by owners and operators for
compliance with allowance-holding
requirements for the 2012 control
periods, and likely impose increased
compliance costs under the Transport
Rule NOX trading programs or impact
the ability to comply with the 2012
limits.
In light of the specific circumstances
in this case and the above-described
legal and technical problems that would
result from a carryover of CAIR NOX
allowances into the Transport Rule
trading programs, the final rule does not
allow any such carryover. EPA agrees
that, as a general principle, it is
desirable to provide continuity between
sequential regulatory programs
involving emission trading and thereby
to ensure that allowances in the past
program continue to have some value in
the new program. Balancing the general
desirability of providing program
continuity against the potential negative
consequences of a carryover in, and the
specific circumstances of, this case, EPA
concludes that the carryover of banked
CAIR NOX allowances into the
Transport Rule trading programs should
not be allowed. EPA notes that, in this
case, it signaled the possibility that it
would take such an approach in order
to provide markets with full information
and avoid unnecessary disruptions.
After CAIR was remanded by the Court
in North Carolina, 550 F.3d 1176, in
December 2008, EPA was concerned
about the future status of CAIR NOX
allowances and consequently advised
the public—through a statement posted
on the EPA Web site in March, 2009—
that ‘‘EPA’s continued recording of
CAIR NOX allowances does not
guarantee or imply that any allowances
will continue to be usable for
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compliance after a replacement rule is
finalized or that they will continue to
have value in the future.’’ 120 EPA
believes its decision to disallow
carryover of banked allowances here
reflects the specific factors in this case
and should not be treated as setting any
precedent for the treatment, in any
future trading programs, of any past
trading program’s banked allowances.
However, EPA notes that, under the
CAIR ozone-season NOX trading
program, where unused allowances
were carried forward from the preceding
NOX Budget Trading Program, and
under the CAIR annual NOX trading
program, where extra allowances (from
the compliance supplement pool) were
allocated for early reductions made
during the NOX Budget Trading
Program, the vast majority of allowance
allocation decisions were made by the
states administering these programs.
Moreover, a number of states did not
allocate CAIR allowances to their
sources using fuel adjustment factors,
whose use the Court rejected in North
Carolina in connection with EPA’s
setting of state NOX emission budgets.
In light of the general desirability of
providing continuity between state
programs, states may want to address
the CAIR NOX banks when developing,
in SIP revisions, the Transport Rule
allowance allocations for control
periods after 2012. EPA encourages each
state that wants to allocate Transport
Rule NOX allowances through SIP
revisions to consider using information
on the CAIR NOX allowance banks that
will remain after 2011. Any such
allowance allocations, of course, must
be within the respective state’s NOX
trading budget, and must be submitted
to EPA within the applicable
submission deadlines, established in the
final rule for the control periods for
which the allocations are made. The
Agency intends to contact states
concerning the desirability of holding a
workshop to discuss issues related to
state allowance allocations.
B. Interactions With NOX SIP Call
The proposed rule explained that
states covered by both the NOX SIP Call
and the Transport Rule would be
required to comply with the
requirements of both rules and that the
Transport Rule would not preempt or
replace the requirements of the NOX SIP
Call. Most, but not all, NOX SIP Call
120 https://epa.gov/airmarkets/business/
cairallowancestatus.html. EPA posed similar
statements in the on-line systems for trading CAIR
NOX allowances. See 40 CFR 96.102 and 96.302
(definitions of ‘‘CAIR NOX Allowance Tracking
System’’ and ‘‘CAIR NOX Ozone Season Allowance
Tracking System’’).
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states would be included in the
Transport Rule. The proposed rule
further explained that the Transport
Rule ozone-season NOX trading program
would achieve the emission reductions
required by the NOX SIP Call from EGUs
serving generators with a nameplate
capacity greater than 25 MW and
producing electricity for sale in most
NOX SIP Call states. (This would not be
the case, of course, for those NOX SIP
Call states not covered by the Transport
Rule.)
The NOX SIP Call states used the NOX
Budget Trading Program to comply with
the NOX SIP Call requirements for EGUs
serving a generator with a nameplate
capacity greater than 25 MW and large
non-EGUs with a maximum rated heat
input capacity greater than 250 mmBtu/
hour. (In some states, EGUs serving a
generator with a nameplate capacity of
25 MW or less were also included in the
NOX Budget Trading Program as a
carryover from the Ozone Transport
Commission NOX Budget Trading
Program.) EPA stopped administering
the NOX Budget Trading Program under
the NOX SIP Call after the completion of
compliance activities related to the 2008
ozone-season control period, and states
used other mechanisms to comply with
the NOX SIP Call requirements.
The proposal further explained that, if
EPA promulgated a final rule that did
not allow the expansion of the
Transport Rule to NOX Budget Trading
Program units, any state that allowed
these units to participate in the CAIR
ozone-season NOX trading program
would need to submit a SIP revision to
address the state’s NOX SIP Call
requirement for the reductions. The
proposal also explained that states in
the CAIR ozone-season NOX trading
program or the NOX Budget Trading
Program that would not be in the
Transport Rule ozone-season NOX
trading program would need to submit
SIP revisions addressing the NOX SIP
Call requirements for any emission
reductions (by EGUs and non-EGUs)
addressed in the NOX Budget Trading
Program and not addressed in some
other way. See 75 FR 45340–41.
As discussed elsewhere in this
preamble, the final Transport Rule
allows states to expand the general
applicability provisions of the Transport
Rule ozone-season NOX trading program
to include small EGUs, which were
included by some states in the NOX
Budget Trading Program, but not for
large non-EGUs, which were included
in the NOX Budget Trading Program.
This will allow states with NOX SIP Call
obligations to meet those requirements
with respect to small EGUs brought into
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48325
the Transport Rule trading program, but
not with regard to large non-EGUs.
With the issuance of the final
Transport Rule, NOX SIP Call
requirements remain in place. See 40
CFR 51.121. EPA is not changing any of
the NOX SIP Call requirements. The
NOX SIP Call generally requires that
states choosing to rely on large EGUs
and large non-EGUs for meeting NOX
SIP Call emission reduction
requirements must establish a NOX mass
emissions cap on each source and
require Part 75, subpart H monitoring.
As an alternative to source-by-source
NOX mass emissions caps, a state may
impose NOX emission rate limits on
each source and use maximum
operating capacity for estimating NOX
mass emissions or may rely on other
requirements that the state demonstrates
to be equivalent to either the NOX mass
emissions caps or the NOX emission rate
limits that assume maximum capacity.
Collectively, the caps or their
alternatives cannot exceed the portion
of the state budget for those sources. See
40 CFR 51.121(f)(2) and (i)(4). EPA will
work with states to ensure that NOX SIP
Call obligations continue to be met (e.g.,
through intrastate cap and trade
programs that require the level of
reductions on which the state has
recently relied).
C. Interactions With Title IV Acid Rain
Program
The final rule does not affect any Acid
Rain Program requirements. Acid Rain
Program requirements are established
independently in Title IV of the CAA
and are not replaced by the Transport
Rule. Title IV sources that are subject to
final Transport Rule provisions still
need to continue to comply with all
Acid Rain provisions. Title IV SO2 and
NOX requirements continue to apply
independently of the Transport Rule
provisions. For the reasons explained
above, Title IV SO2 allowances are not
allowed to be used in the Transport
Rule trading programs. Similarly,
Transport Rule SO2 allowances are not
usable in the Acid Rain Program.
The final Transport Rule does not
include any opt-in unit provisions in
the FIPs and does not allow SIP
revisions to include opt-in unit
provisions in the Transport Rule trading
programs. Consequently, no sources,
including those that have opted in to the
Acid Rain Program, can opt-in to the
Transport Rule trading programs.
There will likely be changes to
emissions at some Acid Rain units
outside of the Transport Rule area as a
result of the transition from CAIR to the
Transport Rule. Namely, emissions at
some non-Transport Rule Acid Rain
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units in the states that border the
Transport Rule states may increase
because of potential load-shifting from
units in Transport Rule states and
because of a potential decrease in the
Title IV allowance price. There is a
discussion of possible emission
increases in non-covered states in
section VI.C of this preamble.
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D. Other State Implementation Plan
Requirements
In this final action, EPA has not
conducted any technical analysis to
determine whether compliance with the
Transport Rule would satisfy RACT
requirements for EGUs in any
nonattainment areas, or Regional Haze
BART-related requirements. For that
reason, EPA is neither making
determinations nor establishing any
presumptions that compliance with the
Transport Rule satisfies any RACT or
BART-related requirements for EGUs.
Based on analyses that states conduct on
a case-by-case basis, states may be able
to conclude that compliance with the
Transport Rule for certain EGUs fulfills
nonattainment area RACT requirements.
EPA intends to undertake a separate
analysis to determine if compliance
with the Transport Rule would provide
sufficient reductions to satisfy BART
requirements for EGUs in accordance
with Regional Haze Rule requirements
for alternative BART compliance
options as soon as practicable following
promulgation of the Transport Rule.
X. Transport Rule State
Implementation Plans
EPA proposed (75 FR 45342) FIPs
setting state-specific emission reduction
requirements for each upwind state
covered by the proposed Transport Rule
and with respect to one or more of three
air quality standards—the 1997 annual
PM2.5 NAAQS, the 2006 24-hour PM2.5
NAAQS, and the 1997 ozone NAAQS.
In CAIR, EPA allowed the states to
replace the CAIR FIP with SIPs and
provided substantial flexibility. In the
proposed Transport Rule, EPA proposed
to allow similar flexibility to states for
addressing the CAA section
110(a)(2)(D)(i)(I) transport issues
through a SIP. EPA proposed to allow a
state to submit a SIP for the ozone
requirements only, for the PM2.5
requirements only, or for both the ozone
and the PM2.5 requirements with the
specific quantity of emission reductions
necessary for a state’s SIP determined
based on the state emission budgets
provided in the final Transport Rule.
EPA received comments suggesting
that if the proposal’s remedy were
finalized, EPA should allow states to
replace the FIP allowance allocation
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provisions in the proposed Transport
Rule trading programs by statedeveloped allocation provisions.
Commenters referenced the two
alternatives provided to states in the
CAIR trading programs where: (1) EPA
adopted a rule and model trading
regulations under which states that
adopted, as state SIP trading programs,
the model regulations (with only certain
limited changes allowed, e.g., in the
allocation provisions) could participate
in the EPA-administered CAIR trading
programs; and (2) EPA adopted a rule
allowing states to adopt in SIPs
provisions replacing only certain
provisions in the CAIR FIPs (e.g., the
allocation provisions) and to remain in
the CAIR trading programs under the
CAIR FIPs. Under both approaches, the
covered units in the state participated in
the CAIR trading programs, albeit with
state-, rather than EPA-, determined
allocations. Comments on the Transport
Rule proposal supported these two
types of approaches for allowing states
to replace EPA allocations under the
proposed Transport Rule trading
programs by state allocations. EPA
requested additional comment on this
topic in the NODA published January 7,
2011 (76 FR 1109).
Two approaches with associated
deadlines were explained in the NODA.
Under the first approach, EPA would
adopt new provisions, as part of the
proposed Transport Rule FIP that would
allow a state to submit a SIP (referred as
an abbreviated SIP) that would modify
specified provisions of the proposed
Transport Rule FIP trading programs.
Specifically, the abbreviated SIP would
substitute state allocation provisions for
control periods in years after 2012,
applicable to one or more of the
proposed Transport Rule FIP trading
programs that apply to the state. The
NODA explained which specific
provisions in the FIP could be replaced.
If the state allocation provisions met
certain requirements and the
abbreviated SIP did not change any
other provisions in the respective
proposed Transport Rule FIP trading
program, then EPA would approve the
abbreviated SIP. In the substitute state
allocation provisions, the state could
allocate allowances to Transport Rule
units (whether existing or new units) or
other entities (such as renewable energy
facilities) or could auction some or all
of the allowances. The NODA went on
to describe the requirements for EPA
approval of an abbreviated SIP (76 FR
1119) including that the total amount of
allowances allocated and auctioned
each year could not exceed the
applicable budget; allocations and
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auction results would need to be
reported to EPA by the permitting
authority (usually the state) by
particular dates prior to the applicable
control period depending on whether
allowances were going to existing or
new sources; the reported allocations
and auction results could not be
changed; and no other provisions of the
FIP would be changed.
Under the second approach, EPA
would adopt a new rule that would
provide that, if a state submitted a SIP
(referred to as a full SIP) that adopted
trading program regulations meeting
certain requirements for control periods
in years after 2012, then EPA would
approve the full SIP as correcting the
deficiency under CAA section
110(a)(2)(D)(i)(I) in the state’s SIP that
was the basis for issuance of the
comparable proposed Transport Rule
FIP. In the state allocation provisions,
the state could allocate allowances to
Transport Rule units (whether existing
or new units, except for opt-in units) or
other entities (such as renewable energy
facilities) or could auction allowances.
Upon EPA approval of a state’s full SIP,
the state’s SIP-based trading program
would be integrated with the
comparable FIP-based Transport Rule
trading program (whether or not
modified by an abbreviated SIP)
covering other states. Moreover, covered
sources in the state could participate in
the integrated trading program, and the
allowances issued under the SIP-based
state trading program would be
interchangeable with the allowances
issued in the comparable FIP-based
Transport Rule trading program.
The NODA went on to describe the
limited changes that states could make
under the full SIP option. Only
allocation provisions could be modified
with the same requirements as for
abbreviated SIPs, including, among
other things, that the total amount of
allowances allocated each year could
not exceed the applicable budget and
that allocations would need to be
reported to EPA by the permitting
authority (usually the state) by
particular dates prior to the applicable
control period depending on whether
allowances were going to existing or
new sources.
The NODA also discussed the option
for states to submit SIPs using emission
reduction approaches other than the
proposed Transport Rule trading
programs to correct the deficiency under
CAA section 110(a)(2)(D)(i)(I) in the
state’s SIP. EPA would review on a caseby-case basis SIPs using such alternative
approaches (76 FR 1120).
Suggested deadlines for abbreviated
and full SIPs were given in tables in the
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NODA (76 FR 1120). These deadlines
generally required states to submit SIPs
about 2 years ahead of a particular
control period for which state
allocations would apply in order to give
EPA time to review and approve the SIP
and record allowances.
Most commenters on the NODA
supported state allocation options,
within the preferred FIP remedy, that
would replace FIP allocations with SIPbased state allocations.
In the final rule, EPA adopts, with
some revisions, both of the approaches
described in the January 7, 2011 NODA.
Under the first approach, a state may
submit an abbreviated SIP that modifies
a final Transport Rule FIP trading
program in only a limited way (i.e., by
replacing the allowance allocation
provisions in §§ 97.411(a) and (b)(1) and
97.412(a) for the annual NOX trading
program, §§ 97.511(a) and (b)(1) and
97.512(a) for the ozone-season NOX
trading program, §§ 97.611(a) and (b)(1)
and 97.612(a) for the SO2 Group 1
trading program, and §§ 97.711(a) and
(b)(1) and 97.712(a) for the SO2 Group
2 trading program). In the state’s
replacement provisions, the state may
allocate allowances to Transport Rule
units (whether existing or new units) 121
or other entities (such as renewable
energy facilities) or may auction
allowances. Additionally, state SIPs can
address one or all of the pollutants
addressed by the FIPs. For PM2.5, EPA
is finalizing the flexibility for a state SIP
to address either SO2 or NOX, or both.
Further, if a state is required to make
ozone-season and annual NOX
reductions, the SIP could address either
ozone-season or annual NOX emissions,
or both. In other words, states can
replace provisions in all FIPs that apply
or some subset of the FIPs that apply to
a particular state, and leave in place the
FIPs for the requirements not addressed
by a SIP.
Further, EPA will approve the
abbreviated SIP only if the state
replacement for the Transport Rule FIP
allocation provisions meets certain
requirements and the abbreviated SIP
does not change any other provisions in
the Transport Rule FIP trading program.
For EPA approval, the state allocation
and, where applicable, auction
provisions (and any accompanying
definitions of terms applying only to
terms as used in these provisions) must
meet the following requirements. First,
the provisions must provide that, for
each year for which the state allocation
and, where applicable, auction
121 EPA is not finalizing opt-in provisions, so the
reference to federal-only opt-in allocations in the
NODA has been removed.
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provisions will apply, the total amount
of control period (annual or ozoneseason) allowances allocated and, where
applicable, auctioned in accordance
with these provisions cannot exceed the
applicable state budget (less any
applicable Indian country new unit setaside, which will continue to be
administered by EPA) for that year
under the relevant Transport Rule FIP
trading program.
Second, to the extent the state
provisions provide for allocations for, or
auctions open to, existing units, the
provisions must require that the state or
the permitting authority under title V of
the CAA for the state submit to the
Administrator final allocations and, if
any auction is to be held, final auction
results in accordance with a schedule of
deadlines discussed below. To the
extent the provisions provide for
allocations for or auctions open to new
units or any other entities, the
provisions must require that the
permitting authority submit to the
Administrator final allocations and, if
applicable, auction results by July 1 of
the year of the control period for which
the allowances will be distributed. The
allocation and auction results must be
final and cannot be subject to
modification (e.g., through an allowance
surrender adjusting the allocation or
auction results).
As noted above, the state’s submission
to the Administrator of allocations or
auction results with regard to existing
units must meet a specified schedule of
deadlines. These submission deadlines
reflect, and are necessarily coordinated
with, the deadlines for recordation by
the Administrator of allowance
allocations and any auction results
under the Transport Rule trading
programs. The recordation deadlines,
which are discussed in detail in section
XI of this preamble, provide that the
Administrator must record existing-unit
allowance allocations and auction
results by: July 1, 2013 for the
applicable control periods in 2014 and
2015; July 1, 2014 for the applicable
control periods in 2016 and 2017; July
1, 2015 for the applicable control
periods in 2018 and 2019; and July 1,
2016 and July 1 of each year thereafter
for the control period in the fourth year
after the year of the applicable
recordation deadline. In order to
provide the Administrator 1 month to
review the submissions of allocations
and auction results to ensure that the
submissions include sufficient
information (e.g., the correct
identification for each unit involved) to
record correctly the submitted
allocations and auction results, the state
or permitting authority must make these
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submissions to the Administrator by:
June 1, 2013 for the applicable control
periods in 2014 and 2015; June 1, 2014
for the applicable control periods in
2016 and 2017; June 1, 2015 for the
applicable control periods in 2018 and
2019; and June 1, 2016 and June 1 of
each year thereafter for the applicable
control period in the fourth year after
the year of the applicable submission
deadline.
Under the second approach, a state
may submit a full SIP adopting a
Transport Rule trading program that
differs from the comparable Transport
Rule FIP trading program only with
regard to limited provisions of the FIP
trading program. First, the full SIP may
include new allocation or auction
provisions instead of the Transport Rule
FIP allowance allocation provisions
other than those concerning the Indian
country new unit set-aside. In the state
allocation or auction provisions, the
state may allocate allowances to
Transport Rule units (whether existing
or new units) or other entities (such as
renewable energy facilities) or may
auction allowances. EPA will approve
the full SIP only if the state allocation
or auction provisions (and any
accompanying definitions of terms
applying only to terms as used in these
provisions) meet certain requirements.
Second, the full SIP may substitute the
name of the state for the term ‘‘State’’ as
used in the FIP trading program
provisions, provided that EPA
determines that the substitutions are not
substantive changes. Third, as discussed
in more detail below, all references to
units in Indian country, as used in the
FIP trading program provisions, must be
removed, and the full SIP cannot
impose any requirements on units in
Indian country within the borders of the
state and may not include the Indian
country set-aside provisions. Other than
these allowed changes, all other
provisions in the Transport Rule trading
program in the full SIP must be the
same as those in the Transport Rule FIP
trading program with regard to nonIndian country units. For EPA approval,
the state allocation provisions must
meet the same requirements, as
discussed above, that state allocation or
auction provisions in an abbreviated SIP
must meet.
A Transport Rule trading program
adopted by a state in a full SIP, and
approved by EPA, under the second
approach will be fully integrated with
the comparable Transport Rule FIP
trading program (i.e., the ‘‘TR NOX
Annual Trading Program’’, ‘‘TR NOX
Ozone Season Trading Program’’, ‘‘TR
SO2 Group 1 Trading Program’’, or ‘‘TR
SO2 Group 2 Trading Program’’
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respectively) for other states. This will
apply whether the comparable
Transport Rule FIP program for other
states was modified by an abbreviated
SIP approved by EPA under the first
approach or was not modified by such
an abbreviated SIP. The integration of
these three types of trading programs
will be accomplished primarily through
the definitions of the terms, ‘‘TR NOX
Annual allowance’’, ‘‘TR NOX Ozone
Season allowance’’, ‘‘TR SO2 Group 1
allowance’’, and ‘‘TR SO2 Group 2
allowance’’ in the full SIPs approved by
EPA and the TR FIP trading programs
(whether or not the programs were
modified by abbreviated SIPs). ‘‘TR NOX
Annual allowance’’ will be defined in
the state and Transport Rule FIP trading
programs as including allowances
issued under any of the following
trading programs: The comparable EPAapproved state Transport Rule trading
programs; the comparable Transport
Rule FIP trading programs with EPAapproved state allocation and auction
provisions; and the Transport Rule FIP
trading programs with EPA allocation
provisions. Similarly, the definitions in
the state and Transport Rule FIP trading
programs of ‘‘TR NOX Ozone Season
allowance’’, ‘‘TR SO2 Group 1
allowance’’, and ‘‘TR SO2 Group 2
allowance’’ respectively will include
allowances issued under all three types
of trading programs. As a result,
allowances issued in one approved state
Transport Rule trading program will be
interchangeable with allowances issued
in the comparable Transport Rule FIP
trading program (whether or not
modified by an abbreviated SIP), and all
these allowances will be available for
use for compliance with the allowanceholding requirements (to cover
emissions and to meet assurance
provision requirements) in all three
types of trading programs.
The integration of state and the
proposed Transport Rule FIP trading
programs will also be reflected in the
definitions of ‘‘TR NOX Annual Trading
Program,’’ ‘‘TR NOX Ozone Season
Trading Program’’, ‘‘TR SO2 Group 1
Trading Program’’, and ‘‘TR SO2 Group
2 Trading Program’’. Each of these
definitions in the state Transport Rule
and Transport Rule FIP trading
programs will expressly encompass the
comparable Transport Rule FIP trading
programs (whether or not modified by
an abbreviated SIP) and the comparable
EPA-approved state full SIP trading
program.
The final rule also sets deadlines for
the submission of complete abbreviated
and full SIPs. These deadlines are based
on the first year for which the state
wants to allocate or auction allowances,
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reflect the above-discussed deadlines for
the Administrator’s recordation of
allocations and auction results, and
build in a 6-month period for EPA
review, provision of notice and
opportunity for public comment, and
approval of the SIP revisions. This 6month period is built into the final
rule’s SIP submission deadlines because
that is the period EPA found was
needed for reviewing, providing notice
and comment for, and approving state
trading program provisions in
abbreviated and full SIPs under CAIR.
As a result, the final rule requires that
complete abbreviated and full SIPs must
be submitted to the Administrator by:
December 1, 2012 in order to govern
allowance allocation and auction for
control periods in 2014 and 2015;
December 1, 2013 in order to govern
control periods in 2016 and 2017;
December 1, 2014 in order to govern
allowance allocation and auction for
control periods in 2018 and 2019; and
December 1, 2015 and by December 1 of
any year thereafter in order to govern
allowance allocation and auction for
control periods in the fifth year after
such submission deadline.
EPA notes that, in cases where a state
that has Indian country within its
borders submits, and EPA approves, a
full SIP, the comparable FIP will not be
entirely replaced. In such cases, the FIP
will continue to be in place with regard
to the Transport Rule trading program
provisions that concern units in Indian
country, and the full SIP will
encompass all other provisions of the
trading program. Specifically, to the
extent Transport Rule trading program
provisions reference and apply to Indian
country units (including, for example,
references in the applicability
provisions and the Indian country new
unit set-aside provisions), those
provisions, as they apply to Indian
country units, will remain in the FIP.
The full SIP will include those
provisions only as they apply to nonIndian country units.
As a practical matter, this means that
the Indian country new unit set-aside
provisions, which apply exclusively to
Indian country new units, will remain
entirely in the FIP. Further, other
trading program provisions that
reference both non-Indian country units
and Indian country units (such as the
applicability provisions) will remain in
the FIP to the extent of their application
to Indian country units and will be
included in the full SIP to the extent of
their application to non-Indian country
units.
However, EPA notes that the
assurance provisions in each Transport
Rule trading program require
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calculations using the entire state
budget, including any portion of the
budget that may be allocated to Indian
country new units. Further, EPA notes
that currently no new units are planned
or anticipated to be located in Indian
country. Under these circumstances,
EPA will handle the assurance
provisions as follows. The full SIP for a
state having Indian country will initially
include the assurance provisions, as set
forth in the FIP, except with removal of
any references to sources and units in
Indian country. The FIP will initially
not include the assurance provisions,
which will be fully effective and
enforceable under the full SIP. In the
event that any new unit is located in
Indian country in the state, EPA intends
to modify its approval of the full SIP to
take back the assurance provisions in
order to apply, in the FIP, the assurance
provisions to both Indian country and
non-Indian country units.
This final rule not only allows a state
to choose to submit an abbreviated or a
full SIP; it also allows a state to choose
to submit either form of SIP to replace
any or all of the FIPs in this rule as they
apply to a particular state. By
promulgating these Transport Rule FIPs,
EPA in no way affects the right of a state
to submit, for review and approval, a
SIP that replaces the federal
requirements of the FIP with state
requirements that do not involve state
participation in the Transport Rule
trading programs. In order to replace the
FIP in a state, the state’s SIP taking an
approach other than participation in
Transport Rule trading programs must
provide adequate provisions to prohibit
NOX and SO2 emissions that are
determined in the Transport Rule to
contribute significantly to
nonattainment or interfere with
maintenance in another state or states.
EPA will review such a SIP on a caseby-case basis. The Transport Rule FIPs
remain fully in place in each covered
state until a state’s SIP is submitted and
approved by EPA to revise or replace a
FIP.
In response to numerous comments
urging EPA to allow states to determine
allowance allocations as soon as
possible, EPA has developed a SIP
revision procedure that applies to 2013
allowance allocations only. In
developing this procedure, EPA is
balancing the desire to allow states the
flexibility to tailor allowance allocations
to the specific needs and situations in
a particular state with the need to
provide certainty to source owners and
operators by having allowances
recorded sufficiently ahead of the
control period for which the allocations
are made in order to facilitate owners’
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and operators’ efforts to optimize their
compliance strategies. This final rule
allows states to make 2013 allowance
allocations through the use of a SIP
revision that is narrower in scope than
the other SIP revisions states can use to
replace the FIPs and/or to make
allocation decisions for 2014 and
beyond. For 2013 allocations, the scope
of the SIP revision is limited to
allocations made to units that
commence commercial operation before
January 1, 2010 and provided in the
form of a list of those units and their
corresponding allocations for 2013.
Additionally, this particular SIP
revision may allocate only the portions
of the state budgets set forth in Tables
X–1 through X–3, i.e., each state budget
minus the new unit set-aside and the
Indian country new unit set-aside.
In developing this procedure, EPA set
deadlines for submissions of the SIP
revisions for 2013 allocations and for
recordation of the allocations that
balanced the need to record allowances
sufficiently ahead of the control period
with the desire to allow state flexibility
for 2013. EPA set deadlines that will
allow sufficient time for EPA to review
and approve these SIP revisions, taking
into account that EPA approval must be
final and effective before the 2013
allocations can be recorded and the
allowances are available for trading. In
order to ensure that EPA review and
approval (which must include public
notice and opportunity for comment)
can be completed in time, the final rule
necessarily limits the allowed scope of
the SIP revisions for 2013 allocations, as
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set forth in the requirements discussed
below, and thereby limits the issues that
must be considered and addressed in
the review and approval process.
Further, the final rule prescribes the
form in which the state allocations for
2013 must be provided to EPA in order
to facilitate rapid recordation of the
allocations upon their approval.
States, along with their sources, will
need to weigh the trade-offs of a
relatively short period of recording
before the control period for which the
allocation is made (about 6 months)
with the desire to have state allocations
in 2013, when deciding whether to
pursue a SIP revision for 2013
allocations. States may choose to submit
a SIP revision for one or more of the
trading programs. In other words, state
allocations for 2013 could apply in one
trading program while 2013 FIP
allocations apply in another.
States can make 2013 allowance
allocations provided the state meets
certain requirements.
• By the date 70 days after
publication of the final rule in the
Federal Register, a state must provide
notification to EPA if the state intends
to submit state allocations for 2013. The
notification must be in a format
prescribed by the Administrator and
submitted electronically.
• By April 1, 2012, the state must
submit a SIP revision to EPA that:
Æ Allocates to existing units 122 only,
provides a list of the units and their
122 Existing unit means a unit that commenced
commercial operation before January 1, 2010.
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48329
state allocations to EPA electronically
and in a format prescribed by EPA, and
does not provide for any change in the
units and allocations on the list and in
any allocation previously determined
and recorded by the Administrator;
Æ Allocates a total amount of
allowances for 2013 that does not
exceed the applicable amount in Tables
X–1 through X–3 for each trading
program that applies in that particular
state; and
Æ Provides for no set-asides and does
not alter the new unit set-asides, the
Indian country new unit set-asides, and
any aspect of the FIP rules other than
the existing-unit allocations for 2013.
If EPA does not receive notification
from a state by the date 70 days after
publication of the final rule in the
Federal Register, EPA will record FIP
allocations for 2012 and 2013 as
scheduled (by the date 90 days after
publication of the final rule). If EPA
receives timely notification from a state,
EPA will record FIP allocations for 2012
only and wait to record 2013
allocations. If the state provides a timely
(not later than April 1, 2012) SIP
revision meeting all the above-described
requirements and EPA approves the SIP
revision by October 1, 2012, EPA will
record state-determined allocations for
2013 by October 1, 2012. Otherwise,
EPA will record the EPA-determined
allocations for 2013.
BILLING CODE 6560–50–P
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BILLING CODE 6560–50–C
EPA will work with states that wish
to submit full SIPs or abbreviated SIPs
to ensure a smooth integration with the
relevant Transport Rule trading
programs. The Agency intends to
provide information and tools to assist
states in their rulemaking efforts,
including electronic versions of the
Transport Rule trading rules and EPA
will work with states that wish to
submit full SIPs or abbreviated SIPs to
ensure a smooth integration with the
relevant Transport Rule trading
programs. The Agency intends to
provide information and tools to assist
states in their rulemaking efforts,
including electronic versions of the
Transport Rule trading rules and other
products states feel may be helpful.
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States that submit approvable full SIPs
or abbreviated SIPs to implement one or
all of the Transport Rule trading
programs are not required to include an
additional technical demonstration
relating to elimination of emissions that
contribute significantly to
nonattainment or contribute to
maintenance in downwind areas.
XI. Structure and Key Elements of
Transport Rule Air Quality-Assured
Trading Program Rules
In order to make the final FIP trading
program rules as simple and consistent
as possible, EPA designed them so that
the final rules (like the proposed rules)
for each of the trading programs (i.e., the
‘‘TR NOX Annual Trading Program’’,
‘‘TR NOX Ozone Season Trading
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Program’’, ‘‘TR SO2 Group 1 Trading
Program’’, and ‘‘TR SO2 Group 2
Trading Program’’) are parallel in
structure and contain the same basic
elements. For example, the rules for the
Transport Rule annual NOX, ozoneseason NOX, SO2 Group 1, and SO2
Group 2 trading programs are located,
respectively, in subparts AAAAA
(§§ 97.401, et seq.), BBBBB (§§ 97.501, et
seq.), CCCCC (§§ 97.601, et seq.), and
DDDDD (§§ 97.701, et seq.) of Part 97 in
Title 40 of the Code of Federal
Regulations. Moreover, the order of the
specific provisions for each trading
program is the same, and the provisions
have parallel numbering. The key
elements of the final Transport Rule
trading program rules are as follows.
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(1) General Provisions
(i) §§ 97.402 and 97.403, 97.502 and
97.503, 97.602 and 97.603, and 97.702
and 97.703—Definitions and
Abbreviations
Most of the definitions in the final
Transport Rule trading program rules
are essentially the same as in the
proposed rules and for each of the
Transport Rule trading programs (except
where necessary to reflect the different
pollutants (NOX and SO2), control
periods (for annual and ozone-season
NOX, and for annual SO2), and
geographic coverage involved in the
trading programs). Moreover, many of
the definitions in the final rules that are
essentially the same as in the proposed
rule are also essentially the same as in
prior EPA-administered trading
programs. However, as discussed in
more detail below, some of the
definitions in the final rules clarify, or
differ from, the definitions in the
proposed rule.
As noted, several definitions in the
final rules are essentially the same as
those both in the proposed rules and in
prior EPA-administered trading
programs. Examples include the
definitions of ‘‘source,’’ ‘‘allowance
transfer deadline,’’ ‘‘owner,’’ ‘‘operator’’,
‘‘Allowance Management System’’ (used
instead of the term ‘‘Allowance
Tracking System’’), and ‘‘continuous
emission monitoring system.’’
One example of a definition in the
final rules that is the same as in the
proposed rule, but that clarifies the
definition used in prior trading
programs is the definition of ‘‘fossil
fuel.’’ In the final rule, the term ‘‘fossil
fuel’’ is defined in general as including
natural gas, petroleum, coal, or any form
of fuel derived from such material,
regardless of the purpose for which such
material is derived. For example, with
regard to consumer products that are
made of materials derived from natural
gas, petroleum, or coal, are used by
consumers, and then are used as fuel,
these materials in the consumer
products qualify as fossil fuel. The
definition in the final rules also
includes language establishing a
narrower meaning of ‘‘fossil fuel’’ that is
not generally applicable, but rather is
applicable only for purposes of applying
the limitation on fossil-fuel use under
the solid waste incineration unit
exemption (which is discussed
elsewhere in this preamble). This latter
portion of the ‘‘fossil fuel’’ definition
makes explicit an interpretation that
EPA adopted in CAIR that—solely for
purposes of applying the fossil-fuel use
limitation in that exemption—the term
‘‘fossil fuel’’ is limited to natural gas,
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petroleum, coal, or any form of fuel
derived from such material ‘‘for the
purpose of creating useful heat.’’ For
example, applying this narrower
meaning, consumer products made from
natural gas, petroleum, or coal are not
fossil fuel, for purposes of determining
qualification under the fossil-fuel use
limitation, because the products (e.g.,
tires) were derived from natural gas,
petroleum, or coal in order to meet
certain consumer needs (e.g., to meet
transportation needs), not in order to
create fuel (i.e., material that would be
combusted to produce useful heat).
As noted above, some of definitions in
the final rules clarify definitions in the
proposed rules. The definitions of
‘‘allowable NOX emission rate’’ and
‘‘allowable SO2 emission rate’’ are
clarified by explaining that such a rate
is the most stringent state or federal
emission rate limitation, expressed in
lb/MWhr or, if originally expressed in
lb/mmBtu, converted to lb/MWhr by
multiplying it by the unit’s heat rate in
mmBtu/MWhr. This clarification
ensures consistency from unit to unit in
determining a unit’s allowable rate.
By further example, while the
proposed rules used the same definition
of ‘‘commence commercial operation’’
as in prior EPA-administered trading
programs, the final rules clarify the
definition. Under the definition in the
proposed rules, a unit that is physically
changed is treated as the same unit.
However, the proposed rules were
unclear about the treatment of a unit
that is replaced and whether moving a
unit to a different location or source
constitutes a physical change. The
definition of ‘‘commence commercial
operation’’ in the final rules clarifies
that a unit that is physically changed
(which includes a unit that is replaced)
continues to be treated, for purposes of
this final rule, as the same unit with the
same commence-commercial-operation
date. The definition also clarifies that
moving a unit to a different location or
source is treated the same as a physical
change, and so the unit continues to be
treated as the same unit. The definition
also clarifies that a unit (the replaced
unit) that is replaced, whether at the
same source or a different source, is
treated as the same unit, while the unit
(the replacement unit) that replaces the
unit is treated as a separate unit with a
new commence-commercial-operation
date. (The definition of ‘‘commence
operation’’ is removed in the final rules
because they do not use this term.)
By further example, while the
proposed rules used the same definition
of ‘‘unit’’ as in prior EPA-administered
trading programs, the final rules clarify
the definition. The ‘‘unit’’ definition is
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clarified by expanding it to incorporate
explicitly the concepts—set forth in the
definition in the final rules of
‘‘commence commercial operation’’ and
thus already applicable to all units—
that a unit that is physically changed,
moved to a different location or source,
or replaced at the same or a different
source continues to be treated as the
same unit and that a replacement unit
at the same source is treated as a
separate unit. EPA believes that it is
preferable to provide a comprehensive
definition of ‘‘unit’’ in one place
because the term is used so frequently
in the final rules.
By further example, the definition of
‘‘nameplate capacity’’ is clarified in the
final rules by explaining that it is
expressed in MWe rounded to the
nearest tenth. This is the same rounding
convention that is used in the reporting
of nameplate capacity to the Energy
Information Administration.
As noted above, some of the
definitions in the final rules are similar
to those in the proposed rules but have
some substantive differences. For
example, in the proposed rules, the
definitions of ‘‘cogeneration unit’’ and
‘‘fossil-fuel-fired’’ are similar to those in
prior trading programs but with changes
to minimize the need for data
concerning individual units or
combustion devices for periods before
1990. In order to qualify as fossil-fuelfired, a unit would have to combust any
amount of fossil fuel in 1990 or
thereafter. In order to qualify as a
cogeneration unit, a unit would have to
meet certain efficiency and operating
standards during the later of: the 12month period starting when the unit
begins producing electricity, or 1990.
For a topping-cycle unit, useful power
plus one-half of useful thermal energy
output of the unit must equal no less
than a certain percentage of the total
energy input and useful thermal energy
must be no less than a certain
percentage of total energy output, and,
for a bottoming-cycle unit, useful power
must be no less than a certain
percentage of total energy input. EPA
proposed to limit to 1990 or later the
historical period for which information
on fuel consumption and on
cogeneration unit efficiency and
operations would be required to apply
the ‘‘fossil-fuel-fired’’ and ‘‘cogeneration
unit’’ definitions. This limitation was
proposed because EPA was concerned
that some owners and operators could
have difficulty obtaining pre-1990
information about older units,
particularly for units whose ownership
has changed over time.
While EPA proposed to use 1990 as
the earliest year for which information
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would be required under these
definitions, EPA requested comment on
whether a more recent year should be
used. As discussed elsewhere in this
preamble, the final rules use 2005
(about 5 years before this rule’s
promulgation), rather than 1990, as the
reference year. Further, because the
language describing the historical time
period used (including the reference
year), appeared in the proposal both in
the ‘‘cogeneration unit’’ definition and
the provisions concerning cogeneration
units in the applicability provisions, the
final rules removed any language about
the historical time period from the
‘‘cogeneration unit’’ definition and
revised the language in the applicability
provisions to use the 2005 reference
year for the requirements for meeting
the exemption for cogeneration units
from the Transport Rule trading
programs. Further, consistent with this
use of 2005 as the reference year, the
‘‘fossil-fuel-fired’’ definition in the final
rule specifically references 2005, rather
than 1990, and as discussed elsewhere
in this preamble, the final rules also use
January 1, 2005 (rather than November
15, 1990) as the reference date
throughout the applicability provisions.
With this change in the reference date
for the requirement to meet the
operating and efficiency standards
under the ‘‘cogeneration unit’’
definition, a unit would have to meet
these standards throughout the later of
2005 or the 12-month period starting
when the unit begins producing
electricity and continuing thereafter.
EPA requested comment on whether
these standards should be applied to a
calendar year when the unit involved
did not combust any fuel, i.e., did not
operate at all. As discussed elsewhere in
this preamble, the final rules expressly
provide that the operating and
efficiency standards do not have to be
met for a calendar year throughout
which a unit did not operate at all.
In addition, under the proposed rules,
if a group of cogeneration units
operating as an integrated cogeneration
system met the efficiency standards, a
topping-cycle unit in that system would
be deemed to meet those standards. EPA
requested comment on whether this
provision should also apply to a
bottoming-cycle unit. As discussed
elsewhere in this preamble, this
provision in the final rules is not
limited to topping-cycle units.
By further example of definitions in
the final rules that have substantive
differences from the definitions in the
proposed rules, the proposed definitions
of ‘‘TR NOX Annual allowance,’’ ‘‘TR
NOX Ozone Season allowance,’’ ‘‘TR
SO2 Group 1 allowance,’’ ‘‘TR SO2
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Group 1 allowance,’’ ‘‘TR NOX Annual
Trading Program,’’ ‘‘TR NOX Ozone
Season Trading Program,’’ ‘‘TR SO2
Group 1 Trading Program,’’ and ‘‘TR
SO2 Group 1 Trading Program’’ are
changed in the final rules. Language is
added to the definitions in order to
reference comparable allowances and
trading programs established through
SIP revisions submitted by states and
approved by the Administrator. As
discussed elsewhere in this preamble,
the final Transport Rule provides that,
if a state submits SIP revisions meeting
certain specified requirements, the state
or permitting authority (rather than the
Administrator) will allocate allowances,
and the covered sources in the state will
participate—along with covered sources
in states remaining subject to the
Transport Rule FIPs—in an integrated,
region-wide air quality-assured trading
program under which both any
allowance allocated by the
Administrator and any allowance
allocated by the state or permitting
authority will each authorize one ton of
emissions of the relevant pollutant and
will be usable by any source for
compliance with the requirement to
hold allowances covering emissions.
As noted above, the final rules
include some definitions that were not
used in prior EPA-administered trading
programs and that reflect unique
provisions of the Transport Rule trading
programs. For example, the terms,
‘‘assurance account,’’ ‘‘TR NOX Annual
unit,’’ ‘‘TR NOX Ozone Season unit,’’
‘‘TR SO2 Group 1 unit,’’ ‘‘TR SO2 Group
2 unit,’’ ‘‘common designated
representative,’’ ‘‘common designated
representative’s assurance level,’’ and
‘‘common designated representative’s
share’’ are used and defined in the final
rule.
While the proposed rules included
definitions for the terms, ‘‘owner’s
assurance level’’ and ‘‘owner’s share,’’
the final rules replace these terms and
instead define the terms, ‘‘common
designated representative,’’ ‘‘common
designated representative’s assurance
level,’’ and ‘‘common designated
representative’s share.’’ This is because,
as discussed elsewhere in this preamble,
the final rules include assurance
provisions similar to those in the
proposed rules but that are
implemented based on groups of units
having a common designated
representative, instead of being
implemented on an owner-by-owner
basis. The definition of ‘‘common
designated representative’’ in the final
rules reflects that the determination of
what groups of units and sources in a
State have a common designated
representative is made based on the
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identity of units’ and sources’
designated representatives as of April 1
of the year after the year of the control
period when a state triggers the
assurance provisions. EPA believes that
the use of this reference date will give
owners and operators greater flexibility
to select common designated
representatives after information about
total state control period emissions is
available and after the allowance
transfer deadline when owners and
operators may prefer to have a
designated representative for their
specific source (rather than a common
designated representative for a larger
group) who is focused on ensuring that
sufficient allowances are held in or
transferred to the source’s account to
cover the sources’ emissions. EPA notes
that the definition of ‘‘common
designated representative’s share’’ is
simpler than the definition of ‘‘owner’s
share’’ because implementing the
assurance provisions at the designated
representative level means it is no
longer necessary to address, in the
definition, owner- and unit-level issues
that may arise when a unit has multiple
owners or where two or more units emit
through the same stack.
Finally, some definitions are added to
the final rules that are not in the
proposed rules. For example, because
the term, ‘‘business day,’’ was used, but
not defined, in the proposed rule, its
meaning was unclear. Specifically, it
was unclear whether a day that was
uniquely a state holiday, and not a
federal holiday, was a business day for
purposes of the federally administered
Transport Rule trading programs, e.g.,
whether the allowance transfer deadline
applicable to all sources in all states in
a Transport Rule trading program could
fall on a day that was a unique state
holiday in one or a few states or
whether the allowance transfer deadline
would be advanced to the next business
day for all sources in all states or
perhaps only for sources in the state
with the state holiday. EPA believes
that, for a federally administered trading
program covering sources in multiple
states, the deadlines should be clear and
uniform for all sources, regardless of the
state in which the sources are located,
and should not be affected by unique
state holidays of which owners and
operators of sources in other states may
not even be aware. Consequently, the
‘‘business day’’ definition is added in
the final rules and means a day that
does not fall on a weekend or a federal
holiday.
By further example, a definition for
‘‘natural gas’’ was added in the final
rules. That definition, as well as the
definition for ‘‘coal,’’ incorporate the
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corresponding definitions in Part 72 of
the Acid Rain Program regulations. The
Part 72 definitions are incorporated
because they are also used in the Part 75
monitoring, reporting, and
recordkeeping provisions, which
provisions are already incorporated in
the final Transport Rule Trading
Program rules. (ii) §§ 97.404 and 97.405,
97.504 and 97.505, 97.604 and 97.605,
and 97.704 and 97.705—Applicability
and Retired Units
The applicability provisions in the
final rules are, except as discussed
herein, essentially the same as in the
proposed rules and for each of the
Transport Rule trading programs. Of
course, for each trading program, the
definition of ‘‘State’’ reflects differences
in the specific states whose electric
generating units are covered by the
respective trading program.
Under the general applicability
provisions of the proposed rules, the
Transport Rule trading programs would
cover fossil-fuel-fired boilers and
combustion turbines serving—at any
time starting November 15, 1990 or
later—an electrical generator with a
nameplate capacity exceeding 25 MWe
and producing power for sale, with the
exception of certain cogeneration units
and solid waste incineration units. As
discussed elsewhere in this preamble,
the general applicability provisions in
the final rules reference January 1, 2005
(about 5 years before this rule’s
promulgation), rather than November
15, 1990.
Cogeneration unit exemption. Under
the final rules (as well as the proposed
rules) certain cogeneration units or solid
waste incinerators otherwise covered by
the general category of covered units are
exempt from the FIP requirements. In
particular, the final rules include an
exemption for a unit that qualifies as a
cogeneration unit throughout the later of
2005 or the first 12 months during
which the unit first produces electricity
and continues to qualify throughout
each calendar year ending after the later
of 2005 or such 12-month period and
that meets the limitation on electricity
sales to the grid. In order to qualify as
a cogeneration unit (i.e., meet the
definition of ‘‘cogeneration unit’’) in the
final rules, a unit (i.e., a boiler or
combustion turbine) must operate as
part of a ‘‘cogeneration system,’’ which
is defined as an integrated group of
equipment at a source (including a
boiler or combustion turbine, and a
steam turbine generator) designed to
produce useful thermal energy for
industrial, commercial, heating, or
cooling purposes and electricity through
the sequential use of energy. In
addition, in order to qualify, a unit must
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be a topping-cycle unit or a bottoming
cycle unit because units that produce
useful thermal energy and useful power
through sequential use of energy either
produce useful power first (i.e., are
topping-cycle units) or produce thermal
energy first (i.e., are bottom-cycle units).
Further, in order to qualify as a
cogeneration unit, a unit also must
meet, on a 12-month or annual basis, the
above described efficiency and
operating standards. As discussed
elsewhere in this preamble, EPA
clarifies that the electricity sales
limitation under the exemption is
applied in the same way whether a unit
serves only one generator or serves more
than one generator. In both cases, the
total amount of electricity produced
annually by a unit and sold to the grid
cannot exceed the greater of one-third of
the unit’s potential electric output
capacity or 219,000 MWhr.
The final rules also clarify when a
unit that meets the requirements for the
cogeneration unit exemption and
subsequently fails to meet all these
requirements loses the exemption and
becomes a covered unit. Such a unit
loses the exemption starting the earlier
of January 1 (or May 1 for the NOX
ozone season trading program) after the
first year during which the unit no
longer meets the ‘‘cogeneration unit’’
definition or January 1 (or May 1) of the
first year during which the unit no
longer meets the electricity sales
limitation.
Solid waste incineration unit
exemption. The final rules also include
an exemption for a unit that qualifies as
a solid waste incineration unit during
the later of 2005 or the first 12 months
during which the unit first produces
electricity, that continues to qualify
throughout each calendar year ending
after the later of 2005 or such 12-month
period, and that meets the limitation on
fossil-fuel use. In contrast, the
exemption for solid waste incineration
units in the proposed rules
distinguished between units
commencing operation before January 1,
1985 and those commencing operation
on or after that date and established
somewhat different criteria for these two
categories of units. As discussed
elsewhere in this preamble, the final
rules remove the distinction based on
whether a solid waste incineration unit
commences operation before January 1,
1985 or on or after January 1, 1985. In
order to be exempt, the unit must
qualify as a solid waste incineration
units during the later of 2005 or the first
12 months during which the unit first
produces electricity, must continue to
qualify throughout each calendar year
ending after the later of 2005 or such 12-
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month period, and must meet the
limitation on fossil-fuel use on a threeyear average basis during the first 3
years of operation starting no earlier
than 2005 and every 3 years of operation
thereafter.
Retired unit exemption. The final rule
provisions exempting permanently
retired units from most of the
requirements of the Transport Rule
trading programs are essentially the
same as in the proposed rules and for
each of the Transport Rule trading
programs. The retired unit provisions
exempt these units from the
requirements for emission monitoring,
recordkeeping, and reporting and for
holding allowances, as of the allowance
transfer deadline, sufficient to cover
their emissions. However, the
permanently retired units in a state
must be included in determining
whether owners and operators must
surrender allowances, and, if so, how
many, to comply with the assurance
provisions (which are discussed
elsewhere in this preamble) if the state’s
total covered-unit emissions exceed the
state assurance level.
Specifically, a common designated
representative must include these units
in determining whether his or her share
of total emissions of covered units in a
state exceed his or her share (generally
based on the allowances allocated to the
units that he or she represents) of the
state trading budget with the variability
limit and thus whether the owners and
operators of the units that he or she
represents have to surrender allowances
under the assurance provisions.
(iii) §§ 97.406, 97.506, 97.606, and
97.706—Standard Requirements
The basic requirements applicable to
owners and operators of units and
sources covered by the Transport Rule
trading programs and presented as
standard requirements in the final rules
are, except as discussed herein,
essentially the same as in proposed
rules and for each of the Transport Rule
trading programs. These basic
requirements include: designated
representative requirements; emissions
monitoring, reporting, and
recordkeeping requirements; emissions
requirements comprising emissions
limitations and assurance provisions;
permit requirements; additional
recordkeeping and reporting
requirements; liability provisions; and
provisions describing the effect of the
Transport Rule trading program
requirements on other CAA provisions.
In particular, the paragraphs
addressing emissions requirements for
owners and operators describe these
requirements in detail and reference
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other sections of the final rules that set
forth the procedures for determining
compliance with the emissions
limitations and assurance provisions.
The paragraphs in the final rules
concerning compliance with the
emissions limitations clarify that
owners and operators of a source and
each covered unit at the source must
hold allowances at least equaling the
total control period emissions of all
covered units at the source. Further, the
paragraphs in the final rules concerning
compliance with the assurance
provisions differ from those in the
proposed rules in that, as discussed
elsewhere in this preamble, the final
rules implement the assurance
provisions based on groups of units
with a common designated
representative, instead of being
implemented on an owner-by-owner
basis, as proposed. Under the final
rules, the assurance provisions are
triggered when total control period
emissions by covered units in a state
(starting in 2012) exceed the state
trading budget plus variability limit. If
the assurance provisions are triggered
for a state for a control period in a given
year, owners’ and operators’
responsibility for the resulting penalty
(i.e., the surrender of allowances for
deduction through the transfer of such
allowances to the assurance account
created by the Administrator for such
owners and operators) is determined on
a common designated representative
basis.
For purposes of implementing the
assurance provisions, covered units in a
state are in effect grouped by common
designated representative (which is
defined as an individual (i.e., a natural
person) who is the designated
representative, as distinguished from
the alternate designated representative,
for a group of one or more units and
sources as of April 1 after the control
period for which the state exceeds the
state assurance level). The control
period emissions of all covered units
with a common designated
representative are compared with the
allowance allocations of such units plus
their share of the state variability limit.
The owners and operators of the units
and sources in each group that has
emissions in excess of allocations plus
share of variability are subject to the
assurance provisions penalty. The
owners and operators of the units and
sources in each group must transfer to
the assurance account created for such
owners and operators a total amount of
allowances equal to two times such
owners’ and operators’ proportionate
share of the state’s excess of covered-
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unit emissions over the state trading
budget plus variability.
The group’s proportionate share is the
percentage resulting from division of the
amount of the group’s excess of
emissions over allocations plus share of
variability by the sum of these excess
amounts for all groups of units with a
common designated representative in
the state. The final rule makes it clear
that this percentage is not rounded to
the nearest whole number, but rather
that the calculated amount of
allowances resulting from application of
this percentage is rounded to the nearest
whole number because, in the Transport
Rule trading programs, only whole (not
fractional) allowances are used. If
instead this percentage were rounded
before its application, each group’s
share would be either 100 percent or 0
percent, which would be contrary to the
intent of the assurance provisions in
both the final rules and the proposed
rules.
The provisions addressing the
assurance requirements in the final
rules reflect this common-designatedrepresentative-based approach. For
example, as discussed elsewhere in this
preamble, these provisions use the
terms, ‘‘common designated
representative’s share’’ and ‘‘common
designated representative’s assurance
level,’’ in lieu of the terms, ‘‘owner’s
share’’ and ‘‘owner’s assurance level,’’
used in the proposed rules. By further
example, these final rule provisions
refer to both ‘‘common designated
representatives’’ and ‘‘owners and
operators,’’ rather than simply
‘‘owners.’’
The final rules also explain what
vintage year (i.e., allocation year) of
allowances can be used in order to
comply with the requirement to cover
emissions and with the requirements of
the assurance provisions. With regard to
emissions during a control period in a
given year, only allowances allocated
for that year or any prior year can be
used to cover such emissions. Further,
only allowances of the following vintage
can be used to meet excess emissions
penalties and assurance penalties
concerning emissions during a control
period in a given year: allowances
allocated for that year, any year before
that year, or the year immediately after
that year. This approach makes the
vintage years usable for excess
emissions and assurance penalties
consistent and helps ensure that
allowances will be available to meet
these obligations.
The final rules also clarify the
standard emission requirements by
explaining further what is meant by the
provision that an allowance is a limited
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authorization to emit. The final rules
clarify that an allowance provides
authorization to emit during the control
period in one year and is limited in both
its use and its duration. For example,
each Transport Rule trading program’s
final rules state that an allowance
provides an emission authorization that
can only be used in accordance with the
requirements of the respective trading
program, such as the requirements
specifying what allowances are
available for use, and how such
allowances must be held or transferred,
in order to cover emissions or meet the
assurance provisions. By further
example, under the final rules, an
allowance continues to provide an
authorization to emit one ton of the
relevant pollutant until the allowance is
deducted, e.g., in order to be used for
compliance with the requirement to
cover emissions or the requirements of
the assurance provisions. Moreover,
under the final rules, the Administrator
has the express authority to terminate or
limit the authorization to emit, and
thereby change the use and duration of
the authorization, described in the final
rules, to the extent he or she determines
to be necessary or appropriate to
implement any provision of the CAA.
The remaining paragraphs in the
standard requirements section address
permitting, recordkeeping and
reporting, liability provisions, and the
effect on other CAA provisions. For
example, the paragraphs concerning
permitting requirements are limited to
stating that no title V permit revisions
are necessary to account for allowance
allocation, holding, deduction, or
transfer and that the minor permit
modification procedures can be used to
add or change general descriptions in
the title V permits of the monitoring and
reporting approach used by the units
covered by each title V permit. These
provisions remain essentially the same
in the final rules as in the proposed
rules.
(iv) §§ 96.407, 97.507, 97.607, and
97.707—Computation of Time
These sections address how to
determine the deadlines referenced in
the Transport Rule trading program
rules and are, except as discussed
herein, essentially the same as in the
proposed rules and for each of the
Transport Rule trading programs. The
final rules revise the proposed rule
provisions concerning the treatment of
the final date in any time period in
order to make the provision consistent
with the approach discussed above with
regard to the new definition of
‘‘business day.’’ The revised provision
states that, if the final date is not a
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‘‘business day’’, then the time period is
extended to the next ‘‘business day.’’
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(v) §§ 97.408, 97.508, 97.608, 97.708 and
Part 78—Administrative Appeal
Procedures
Under the final Transport Rule, final
decisions of the Administrator under
the Transport Rule trading programs are
appealable to EPA’s Environmental
Appeals Board under the regulations set
forth in Part 78 (40 CFR part 78), which
are revised by the final Transport Rule
to accommodate such appeals. The
provisions in the final Transport Rule
concerning appeals are, except as
discussed herein, essentially the same
as in the proposed Transport Rule. The
proposed Transport Rule would add a
provision in Part 78 explaining who is
an ‘‘interested person’’ with regard to a
decision, i.e., a person who submitted
comments, testimony, or objections as
part of the process of making the
decision or a person who submitted his
or her name to the Administrator to be
placed to an interested persons list. The
final Transport Rule includes that
provision, but with additional language
that clarifies the process for submitting
a name to be placed on such a list.
(2) Allowance Allocations
Sections 97.410 through 97.412,
97.510 through 97.512, 97.610 through
97.612, and 97.710 through 97.712 set
forth: certain information related to
allowance allocation and for
implementation of the assurance
provisions; the timing for allocation of
allowances to existing and new units;
and the procedures for new unit
allocations. In particular, these sections
include tables providing, for each state
covered by the particular Transport Rule
trading program and for each year, the
state trading budget (without the
variability limit), new unit set-aside,
Indian country new unit set-aside
(where applicable), and variability limit.
These provisions in the final rules differ
in several ways, from the proposed rules
and are essentially the same for each of
the Transport Rule trading programs.
With regard to the tables in the final
rules for the state trading budgets
(without the variability limits), new unit
set-asides, and variability limits, the
identity of the specific states involved
and the values for each state differ from
the tables in the proposed rules. The
final rule values reflect the
determinations and modeling
underlying the final rules and discussed
elsewhere in this preamble. Further, as
discussed elsewhere in this preamble,
the variability limits are only those
based on one-year variability and not
those proposed to be based on three-
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year variability, and Indian country setasides are shown for states with Indian
country within their borders.
With regard to existing unit
allocations, the final rules provide that
these allocations will be set forth in a
notice of data availability to be issued
by the Administrator. In contrast, the
proposed rules stated that existing unit
allocations would be set forth in an
appendix to the rules for each Transport
Rule trading program. EPA believes that
including these allocations in a notice of
data availability referencing the EPA
Web site (rather than publishing them in
tables requiring a large number of pages
in the Federal Register for each
Transport Rule trading program) is a
more efficient method of making these
allocations public, particularly since
these allocations may be changed for
2013 and thereafter by states through
SIP revisions. In addition, under the
final rules the allocations for an existing
unit can change if the unit does not
operate (i.e., has no heat input) for 2
consecutive years starting in 2012. In
that case, the unit continues to receive
its existing unit allocation for those
years plus only 2 more years. As
explained elsewhere in this preamble,
this is a modification of the proposed
rules, under which a unit that did not
operate for 3 consecutive years would
continue to receive its existing unit
allocation for those years plus 3 more
years.
Under the final rule provisions for
new units, the Administrator allocates
allowances from the new unit set-aside
for the state where the respective unit is
located and for each year when the unit
first becomes eligible for an allocation
and each year thereafter. The units
eligible for new unit set-aside
allocations include units commencing
commercial operation on or after
January 1, 2010, as well as several other
categories of units, such as, for example,
existing units that were not initially but
then become covered units, existing
units whose allocations are lost due to
lack of unit operation and that
subsequently begin operating again, and
units that lost their allocations because
they changed location from one state to
another. The approach in the final rules
differs from the proposed rules, which
required that owners and operators
initially request allowances from the
new unit set-aside when the unit first
became eligible for an allocation. As
discussed elsewhere in this preamble,
under the final rules, EPA identifies
which units become eligible and when
they become eligible, based on
information provided in other
submissions (e.g., certificates of
representation, monitoring system
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48337
certifications, and quarterly emissions
reports) that such units must make to
EPA, and the requirement that owners
and operators submit requests for new
unit set-aside allocations is removed in
the final rules.
The final rules also provide for two
rounds of allocations from the new unit
set-aside, in contrast with the proposed
rules that provided for only one round.
In the first round in the final rules (as
in the single round in the proposed
rules), a unit’s new unit set-aside
allocation initially equals that unit’s
emissions—as determined in
accordance with §§ 97.430–97.435,
97.530–97.535, 97.630–97.635, and
97.730–97.735 of the final rules and Part
75 (40 CFR part 75)—for the control
period (annual or ozone season,
depending on the Transport Rule
trading program involved) in the
preceding year. If the new unit set-aside
lacks sufficient allowances to provide
this initial allocation for all of the new
units, then each new unit is allocated its
proportionate share (based on its initial
allocation amount) of the allowances in
the new unit set-aside. The
Administrator issues a notice of data
availability informing the public of the
specific new unit allocations and
provides an opportunity for submission
of objections on the grounds that the
allocations are not consistent with the
requirements of the relevant final rule
provisions. A second notice of data
availability is subsequently issued in
order to make any necessary corrections
in the specific new unit allocations. As
discussed elsewhere in this preamble,
the final rules establish a somewhat
different schedule for issuance of these
notices of data availability than the
proposed rules. In particular, a single
set of dates (i.e., for the first notice, June
1 of the year for which the new unit
allocations are described in the notice
and, for the second notice, August 1 of
that year) is established for all of the
Transport Rule trading programs. For
the reasons discussed elsewhere in this
preamble, the final rules provide for a
second round of allocations to the
extent that any allowances remain in the
new unit set-aside after the allocations
are made to new units in the first round.
(In the proposed rules, remaining
allowances were immediately allocated
to existing units.) The units eligible for
allocations in the second round are new
units that commenced commercial
operation during the control period for
which allocations are being made and
during the prior control period. The
second round allocation for each such
unit initially equals the positive
difference (if any) between the unit’s
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first round allocation (if any) and the
unit’s emissions during the control
period for which allocations are being
made. If the amount of allowances
remaining in the new unit set-aside after
the first round is insufficient to provide
this initial allocation for all of the
second round new units, then each such
new unit is allocated its proportionate
share of the allowances remaining in the
new unit set-aside. The Administrator
uses notices of data availability (which
are issued by December 15 (for the
annual trading programs) and
September 15 (for the ozone season
trading program) of the control period
involved and February 15 (for the
annual trading programs) and November
15 (for the ozone season trading
program) before the allowance transfer
deadline for the control period
involved, in a manner analogous to the
use of such notices in the first round, to
inform the public about the
identification of the new units in the
second round allocations and obtain
and consider any objections. The
February 15 and November 15 notices
also inform the public about the
amounts of the second round
allocations. If, after both rounds of
allocations, any allowances remain in
the new unit set-aside, those allowances
are allocated to existing units in
proportion to such units’ allocations.
The final rules also establish a
separate Indian country new unit setaside in each state where Indian country
is located (i.e., in Florida, Iowa, Kansas,
Louisiana, Michigan, Minnesota,
Mississippi, Nebraska, New York, North
Carolina, South Carolina, Texas, and
Wisconsin). As discussed elsewhere in
this preamble, the Administrator
operates the Indian country new unit
set-aside in essentially the same manner
as state new unit set-aside, except that
unallocated allowances remaining in the
Indian country new unit set-aside after
the two rounds of new unit set-aside
allocations are first placed in the new
unit set-aside in the state where the
Indian country involved is located and
then, if still unallocated, are allocated to
existing units in the state. As with the
state new unit set-aside, EPA will
identify the new units qualifying for the
Indian country new unit set-aside,
calculate the allocations, and issue
notices of data availability using the
same schedules as notices for the state
new unit set-aside.
Under the final rules (like under the
proposed rules), if a unit in certain
specified categories is allocated
allowances that should not have
received them, the Administrator
applies procedures under which the
allocation is not recorded or the amount
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of the recorded allocations is deducted
as an incorrect allocation, with one
exception. The exception is where the
determination of compliance with the
emissions limitation (i.e., requirement
to hold allowances covering emissions,
as distinguished from the assurance
provisions) for the source that includes
the unit has already been completed, in
which case no action is taken to account
for the erroneous allocation for the
control period involved.
While this procedure concerning
recordation or deduction of allocations
is the same as under the proposed rules,
the final rules change the description of
the circumstances under which this
procedure concerning recordation or
deduction of allocations is applied.
Under both the final rules and the
proposed rules, this procedure is
applied to a unit (whether an existing
unit or a new unit) that receives an
allocation but is not actually a covered
unit. However, under the final rules,
another category of units—i.e., any
existing unit that is not located—as of
January 1 of the control period for
which the allocation is received—in the
state from whose trading budget the
allocation was made is also subject to
this procedure. Although relatively few
units are moved from one state to
another, EPA believes that it is
important to address what happens to
such units’ allocations, both because
each state has a limited trading budget
out of which all allocations for a year to
existing and new units in that state must
be made and because, under the
assurance provisions, determinations
are made about owners’ and operators’
surrender of allowances based on,
among other things, the allocations for
units in a specific state. Because, under
the final rules, a unit that is moved from
one state to another may lose its existing
unit allocation in the first state under
the above-described procedure, the final
rules also makes such a unit eligible for
allocations from the new-unit set-aside
of the second state.
Finally, the final rules remove, as no
longer necessary, one category of units
that the proposed rules included as
subject to this procedure. The proposed
rules, treated, as existing units, some
units that had not yet operated but were
projected to operate by January 1, 2012,
and so the proposed rules made these
units subject to the procedure for not
recording or for deducting allocations if
they actually were not required to
certify their monitoring systems and
hold allowances covering emissions
starting January 1, 2012. The final rule
does not treat projected units as existing
units and so this category of units no
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longer needs to be made subject to this
procedure.
(3) Designated Representatives and
Alternate Designated Representatives
Sections 97.413 through 97.418,
97.513 through 97.518, 97.613 through
97.618, and 97.713 through 97.718
establish the procedures for certifying
and authorizing the designated
representative, and alternate designated
representative, of the owners and
operators of a source and the units at the
source, and for changing the designated
representative and alternate designated
representative. These sections also
describe the designated representative’s
and alternate designated
representative’s responsibilities and the
process through which he or she can
delegate to an agent the authority to
make electronic submissions to the
Administrator. Except as discussed
herein, the provisions in the final rules
are essentially the same as in the
proposed rules and for each of the
Transport Rule trading programs.
The designated representative is the
individual (i.e., the natural person)
authorized to represent the owners and
operators of each covered source and
covered unit at the source in matters
pertaining to all Transport Rule trading
programs to which the source and units
were subject. One alternate designated
representative (also an individual) can
be selected to act on behalf of, and
legally bind, the designated
representative and thus the owners and
operators. Because the actions of the
designated representative and alternate
legally bind the owners and operators,
the designated representative and
alternate must submit a certificate of
representation certifying that each was
selected by an agreement binding on all
such owners and operators and is
authorized to act on their behalf.
In the final rules (like in the proposed
rules), the certificate of representation
must contain: Specified identifying
information for the covered source
(including location) and the covered
units at the source and for the
designated representative and alternate;
the name of every owner and operator
of the source and units; and certification
language and signatures of the
designated representative and alternate.
The final rules require an additional
piece of identifying information, i.e.,
whether the unit is located in Indian
country. This is necessary in order for
the Administrator to implement the
above-described Indian country new
unit set-aside. All submissions (e.g.,
monitoring plans, monitoring system
certifications, and allowance transfers)
under the final rules for a covered
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source or covered unit must be
submitted, signed, and certified by the
designated representative or alternate,
except that electronic submission may
be delegated.
In order to change the designated
representative or alternate, a new
certificate of representation must be
received by the Administrator. A new
certificate of representation must also be
submitted to reflect changes in the
owners and operators of the source and
units involved. The new certificate must
be submitted within 30 days of such
changes.
The final rules make explicit an
implied requirement of the proposed
rules, i.e., that, if a unit is added to a
source or is moved from one source to
a second source, a certificate of
representation needs to be submitted to
reflect the change. This requirement is
implicit in the proposed rules when a
unit is added to a source because the
designated representative would not be
authorized to make submissions
concerning the added unit unless that
unit were included on the certificate of
representation. Similarly, where a unit
is moved to another source, new
certificates of representation would
need to be submitted in order for the
correct designated representative to be
authorized to make submissions
concerning the moved unit. Moreover,
because compliance accounts in the
Allowance Management System would
cover all units at a given source and
would be based on the information in
the certificate of representation
submitted by the designated
representative for the source, when a
unit is moved from a source to a second
source, the designated representative of
the second source would need to submit
a certificate of representation removing
the moved unit from the list of units.
The final rules explicitly require that
a new certificate of representation be
submitted to reflect changes (whether
caused by the addition or removal of
units) in which units are located at a
source. In addition, the final rules
impose a deadline on the submission
requirement of 30 days from the date of
the change in the units. This is
analogous to the maximum time period
between a change in a unit’s owner or
operator and the deadline for
submission of a new certificate of
representative reflecting to the change.
Long before any actual move of a unit
to a new location, owners and operators
will need to make decisions about, and
plan the implementation of, such a
move. Consequently, EPA believes that
a 30-day deadline after any move for
reflecting the move in the certificate of
representation is reasonable. In the
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event the change involves the addition
of a unit that operated before being
located at the source, the final Transport
Rule also requires that the designated
representative provide in the certificate
of representation information on the
entity from which the unit was
obtained, the date on which the unit
was obtained, and the date on which the
unit became located at the source. In the
event of a change involving the removal
of a unit, the designated representative
must provide in the certificate of
representation information on the entity
that obtained the unit, the date on
which that entity obtained the unit, and
the date on which the unit became no
longer located at the source. This
information will enable the
Administrator to determine what
actions are necessary to reflect the
change in units located at the sources
involved. For example, if a covered unit
is moved from one source to second
source, the Administrator will have the
information necessary to determine
whether the unit’s allocation should be
changed to reflect movement of the unit
from one state to another.
(4) Allowance Management System
Sections 97.420 through 97.428,
97.520 through 97.528, 97.620 through
97.628, and 97.720 through 97.728
establish the procedures and
requirements for using and operating
the Allowance Management System
(which is the electronic data system
through which the Administrator
handles allowance allocation, holding,
transfer, and deduction), and for
determining compliance with the
emissions limitations and assurance
provisions, in an efficient and
transparent manner. The Allowance
Management System also provides the
allowance markets with a record of
ownership of allowances, dates of
allowance transfers, buyer and seller
information, and the serial numbers of
allowances transferred. Except as
discussed herein, these sections of the
final rules are essentially the same as in
the proposed rules and for each of the
Transport Rule trading programs.
(i) §§ 97.420, 97.520, 97.620, and
97.720—Compliance, Assurance, and
General Accounts
Under the final rules, the Allowance
Management System contains three
types of accounts. One type comprises
compliance accounts, one of which the
Administrator establishes for each
covered source upon receipt of the
certificate of representation for the
source. A compliance account is the
account in which all allowance
allocations must be recorded and in
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48339
which any allowances used by the
covered source for compliance with the
emission limitations must be held. The
designated representative and alternate
for the source are also the authorized
account representative and alternate for
the compliance account.
A second type comprises general
accounts, which can be established by
any entity upon receipt by the
Administrator of an application for a
general account. General accounts can
be used by any person or group for
holding or trading allowances. To open
a general account, a person or group
must submit an application for a general
account, which is similar in many ways
to a certificate of representation. The
provisions for changing the authorized
account representative and alternate, for
submitting a superseding application to
take account of changes in the persons
having an ownership interest with
respect to allowances, and for delegating
authority to make electronic
submissions are analogous to those
applicable to comparable matters for
designated representatives and
alternates.
A third type comprises assurance
accounts. The Administrator establishes
one assurance account for each group of
units having a common designated
representative and located in a state
where the assurance provisions are
triggered by total emissions exceeding
the state trading budget plus variability.
(ii) §§ 97.421 Through 97.423, 97.521
Through 97.523, 97.621 Through
97.623, and 97.721 Through 97.723—
Recordation of Allowance Allocations
and Transfers
Under the final rules, by November 7,
2011, the Administrator must record
allowance allocations for existing units,
as set forth in a required notice of data
availability, for the Transport Rule
annual NOX, ozone-season NOX, and
SO2 trading programs for 2012 and
2013, unless, as discussed elsewhere in
this preamble, a state notifies the
Administrator that the state will submit
a SIP revision with existing-unit
allocations for 2013 by May 1, 2012. If
the Administrator approves that SIP
revision by October 1, 2012, the
Administrator will record the statedetermined existing-unit allocations for
2013, and, in the absence of such
approval by that date, the Administrator
will record the EPA-determined
existing-unit allocations for 2013. By
July 1, 2013, the Administrator must
record existing-unit allowance
allocations (whether EPA- or statedetermined) for each Transport Rule
trading program for 2014 and 2015. By
July 1, 2014, the Administrator must
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record existing-unit allowance
allocations for each Transport Rule
trading program for 2016 and 2017. By
July 1, 2015, the Administrator must
record existing-unit allowance
allocations for each Transport Rule
trading program for 2018 and 2019. By
July 1, 2016 and July 1 of each year
thereafter, the Administrator must
record existing-unit allowance
allocations for each Transport Rule
trading program for the control period
in the fourth year after the year of the
applicable recordation deadline. By
August 1, 2012 and August 1 of each
year thereafter, the Administrator must
record new-unit allowance allocations
for each Transport Rule trading program
for that year. These recordation
deadlines differ from those in the
proposed rules for two reasons. First, as
discussed elsewhere in this preamble,
EPA is adopting provisions that allow
states to submit, and EPA to approve,
SIP revisions (abbreviated or full SIPs)
under which the state, rather than the
Administrator, determines the
distribution of allowances under one or
more of the Transport Rule trading
programs applicable in the state. In
selecting allocation recordation
deadlines, EPA took into account and
balanced certain countervailing factors.
On one hand, EPA considered the need
to provide a reasonable time for a state
to develop, propose, and finalize, and
for EPA to review and propose and
finalize approval of, the SIP revision
and the desirability of providing a
reasonable opportunity for state
distributions to become effective for a
year relatively soon after the 2012
commencement of the Transport Rule
trading programs. EPA’s experience
with prior trading programs has shown
that the process for development and
submission of SIP revisions by states
and approval by EPA in many cases is
about 18 months and in some cases even
longer. On the other hand, EPA
considered the desirability of owners
and operators having allocations in their
compliance accounts a reasonable time
before the year for which the allocations
are made (i.e., the vintage year). Having
the allocations recorded, to the extent
possible, before the vintage year
facilitates compliance decisions and use
of the allowance market in
implementing such decisions. EPA
believes that optimally allocations
would be recorded at least 3 years in
advance of the vintage year.
In balancing these countervailing
factors, EPA is adopting an allocation
recordation schedule that provides
initially for recordation ranging from 6
months to 18 months before the
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beginning of the control period in the
first 2 years (i.e., 2012 and 2013) for
which allocations are made and that, as
allocations for control periods in
subsequent years are recorded,
gradually increases the amount of time
between recordation and the beginning
of the year of the control period
involved until allocations are recorded
about three and one-half years in
advance. With regard to the need to
facilitate states’ distribution of
allowances, this approach gives states
multiple opportunities to develop,
submit, and obtain EPA approval for
SIPs under which the states (rather than
EPA) will distribute allowances under
the Transport Rule trading programs for
control periods relatively early in the
programs. Because of time (which has in
the past ranged from about 6 months to
about 2 years) it may take for a state to
develop and submit such a SIP and
because of the time (which has in the
past been at least 6 months) it will likely
take EPA to review and approve such a
SIP, EPA believes that 2013 is the first
year for which a state can determine
allowance distributions and have them
recorded some minimal time before the
control period involved. With regard to
the need to record allowances in
advance, this approach achieves
recordation at least 6 months in advance
and eventually achieves recordation by
what EPA believes is an optimal amount
of time (greater than 3 years) before the
control period for which recorded
allowances are issued.
As discussed elsewhere in this
preamble, the approach to allowance
recordation in the final rules results in
following schedule for submission of
abbreviated or full SIPs under the final
Transport Rule. SIP revisions with
existing-unit allocations for 2013
control periods must be submitted to the
Administrator by April 1, 2012.
Complete abbreviated and full SIPs
must be submitted to the Administrator
by: December 1, 2012 in order to govern
allowance allocation and auction for
control periods in 2014 and 2015;
December 1, 2013 in order to govern
control periods in 2016 and 2017;
December 1, 2014 in order to govern
allowance allocation and auction for
control periods in 2018 and 2019; and
December 1, 2015 and by January 1 of
any year thereafter in order to govern
allowance allocation and auction for
control periods in the fifth year after the
year of such submission deadline.
The second reason for the differences
in the recordation deadlines in the final
rules, as compared to the proposed
rules, is that, in order to simplify the
recordation schedule for owners and
operators and EPA, EPA set uniform
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recordation deadlines for all of the
Transport Rule trading programs. EPA
believes that these deadlines provide
the Agency sufficient time, after receipt
of any information necessary to
determine allocations (e.g., for new unit
set-aside allocations, the emission data
from the control period in the prior
year), to complete the recordation of
allocations and, as discussed above,
makes the allocations available to
owners and operators before the year for
which the allocations are made. EPA
notes that these are deadlines and that
the Administrator has the discretion,
where feasible and appropriate, to
record allocations before such
deadlines.
Under the final rules (as under the
proposed rules), the process for
transferring allowances from one
account to another is quite simple. A
transfer is submitted providing, in a
format prescribed by the Administrator,
the account numbers of the accounts
involved, the serial numbers of the
allowances involved, and the name and
signature of the transferring authorized
account representative or alternate. If
the transfer form containing all the
required information is submitted to the
Administrator and, when the
Administrator attempts to record the
transfer, the transferor account includes
the allowances identified in the form,
the Administrator records the transfer
by moving the allowances from the
transferor account to the transferee
account within 5 business days of the
receipt of the transfer form.
(iii) §§ 97.424, 97.524, 97.624, and
97.724—Compliance With Emissions
Limitations
Under the final rules (as under the
proposed rules), once a control period
has ended (i.e., December 31 for the
Transport Rule NOX and SO2 annual
trading programs and September 30 for
the ozone-season NOX trading program),
covered sources have a window of
opportunity—until the allowance
transfer deadline of midnight on March
1 or December 1 following the control
period for the annual and ozone season
trading programs respectively—to
evaluate their reported emissions and
obtain any allowances that they need to
cover their emissions during that
control period. Each allowance issued
in each Transport Rule trading program
authorizes emission of one ton of the
pollutant involved, and so is usable for
compliance in that trading program, for
a control period in the year for which
the allowance was allocated or a later
year. Consequently, each source needs—
as of the allowance transfer deadline—
to have in its compliance account, or
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properly submit a transfer that moves
into its compliance account, enough
allowances usable for compliance to
authorize the source’s total emissions
for the control period.
If a source fails to hold sufficient
allowances for compliance to cover the
emissions, then the owners and
operators must provide, for deduction
by the Administrator, two allowances
allocated for the control period, in the
year of when the emissions occurred,
any prior year, or the year immediately
after the year of the emissions, for every
allowance that the owners and operators
failed to hold as required to cover
emissions. In addition, the owners and
operators are subject to discretionary
civil penalties for each violation.
(iv) §§ 97.425, 97.525, 97.625, and
97.725—Compliance With Assurance
Provisions
Under the final rules (as under the
proposed rules), the assurance
provisions ensure that each state will
eliminate its significant contribution to
nonattainment and interference with
maintenance that EPA identifies in this
action. A requirement that owners and
operators surrender allowances under
the assurance provisions is triggered
only for certain owners and operators of
sources and units in a state where the
total state covered-unit emissions for a
control period exceed the applicable
state trading budget with the variability
limit. Moreover, the surrender
requirement is implemented based on
groups of sources and units with a
common designated representative. For
each group of sources and units with a
common designated representative, the
owners and operators of such sources
and units must surrender allowances
only if the units’ emissions (referred to
as the common designated
representative’s share of emissions)
during the control period involved
exceed the units’ allocations plus share
of the state variability limit (referred to
as the common designated
representative’s share of the state
trading budget with variability).
As discussed elsewhere in this
preamble, EPA decided to implement
the assurance provisions on a common
designated representative basis, rather
than on an owner basis. The final rules
implement in a series of steps the
process of determining which states
have total covered-unit emissions
sufficient to trigger the allowance
surrender requirement for a given
control period and determining, using
the approach based on common
designated representatives, which
owners and operators are subject to the
allowance surrender and whether those
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owners and operators are in compliance.
This common-designatedrepresentative-based process is more
streamlined than the owner-based
process in the proposed rules.
First, the Administrator performs the
calculations necessary to determine
whether any state has total covered-unit
emissions for a control period greater
than the state trading budget with the
1-year variability limit. As discussed
elsewhere in this preamble, EPA
decided not to use a 3-year variability
limit because, among other things, such
a limit seems unnecessary to ensuring
elimination of significant contribution
to nonattainment and interference with
maintenance and would make
compliance planning extremely difficult
for owners and operators. By June 1,
2013 and June 1 of each year thereafter,
the Administrator promulgates a notice
of data availability of the results of these
calculations.
Second, by July 1, for states identified
in the June 1 notice of data availability
as having emissions exceeding the state
trading budget with variability, the
designated representative of each new
unit in the state that operated during but
did not receive an allocation for the year
involved must submit a statement to the
Administrator with certain information
about the unit. This information—i.e.,
the unit’s allowable emission rate for
the pollutant involved (NOX or SO2) and
heat rate—is used to calculate a
surrogate allocation for the unit to be
used solely for the purposes of
determining whether the group of units
with a common designated
representative that includes the unit had
emissions exceeding allocations plus
share of the state’s variability limit.
Third, the Administrator calculates,
for each state identified in the June 1
notice of data availability and for each
common designated representative of a
group of units (which groups can
include one or more units and sources)
in the state, the common designated
representative’s share of emissions, the
common designated representative’s
share of the state trading budget with
the variability limit, and the amount (if
any) that the groups of owners and
operators of units represented by the
common designated representative
(which groups can include one or more
owners and operators) in the state must
surrender under the assurance
provisions (i.e., the common designated
representative’s proportionate share of
the excess of state emissions over the
state trading budget with the variability
limit). The Administrator promulgates
by August 1 a notice of data availability
of the results of these calculations,
provides an opportunity for submission
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48341
of objections, and promulgates by
October 1 a second notice of data
availability of any necessary
adjustments to the calculations. In
contrast with the proposed rules,
objections may be submitted concerning
information in the August 1 notice,
whether or not that information was
also provided in the June 1 notice. In
short, the process of issuing notices is
shortened in the final rules by providing
one, comprehensive opportunity to
submit objections to the June 1 and
August 1 notices, rather than two
separate opportunities, one for each
notice.
Also in contrast with the proposed
rules, the deadlines for issuance of
notices of data availability for
implementation of the assurance
provisions are made uniform under the
final rules for all of the Transport Rule
trading programs. EPA is taking this
approach for the same reasons that the
deadlines for issuance of notices of data
availability for new unit set-aside
allocations are made uniform for all of
these trading programs.
Fourth, the owners and operators
identified in the October 1 notice of data
availability as being required to
surrender allowances under the
assurance provisions must transfer, by
November 1, to the assurance account
created by the Administrator for such
owners and operators the amount of
allowances (usable for compliance) that
the Administrator determined in the
October 1 notice of data availability.
Where the October 1 notice indicates
that a specified surrender amount is
owed by a group of two or more owners
and operators, all the group members
are liable for the surrender amount, and
it is up to the owners and operators in
the group to decide who will actually
surrender allowances. This is analogous
to the situation where a group of two or
more owners and operators of covered
units at a source is required to hold
allowances covering the unit’s
emissions and therefore the group of
owners and operators is liable. See 58
FR 3590, 3599 (January 11, 1993)
(discussing liability of owners and
operators under allowance-holding
requirements of the Acid Rain Program).
EPA believes that the approach of
making the owners and operators
responsible for deciding which of them
will actually surrender the necessary
allowances under the assurance
provisions is reasonable because the
identity of who is an owner or operator
(particularly who is an owner) of a unit
or source and the percentage of an
owner’s share can change during the
year and this information is available to
the owners and operators on an ongoing
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basis, and not to EPA unless EPA were
to impose new requirements for
reporting this information. Further, EPA
believes that it is reasonable to leave to
private agreements the establishment of
procedures for determining when, and
under what conditions, specific owners
and operators will provide the
allowances for surrender. Owners and
operators already make these types of
determinations with regard to the
surrender requirements in meeting the
emissions limitations and any excess
emission penalties.
As part of implementing the commondesignated-representative-based
approach of the assurance provisions in
the final Transport Rule, the final rules
provide that the Administrator (instead
of the owners, as in the proposed rules)
will create an assurance account for
each group of the owners and operators
of units and sources with a common
designated representative in each state
where the assurance provisions are
triggered. Because the final rules require
owners and operators to transfer
surrendered allowances to the
appropriate assurance account (rather
than requiring the Administrator to
deduct from accounts established by the
owners), there is no need for the
proposed rule provisions concerning
identification of which allowances are
to be deducted and first-in, first-out
deduction in the absence of such
identification.
The final rules provide that, in
general, the surrender amounts
specified in the October 1 notice for
owners and operators are final and will
not be revised even if the underlying
data (e.g., emission data) used in the
calculations underlying the October 1
notice are subsequently revised.
However, the final rules set forth
limited exceptions to this: Where such
data are revised as a result of a decision
in or settlement of litigation concerning
the data on appeal. EPA believes that
the limitation on revisions of the
surrender amounts specified in the
October 1 notice are necessary to
provide some certainty to owners and
operators and avoid the potential for
multiple changes in owners’ and
operators’ required surrender amounts.
Because the surrender amount for each
group of owners and operators of units
and sources with a common designated
representative in a state is calculated
using emission data from all of the
covered units in that state, each change
in one or a few units’ emission data that
might occur after issuance of the
October 1 notice could otherwise
change the calculated surrender
amounts for all or many groups in the
state. For the limited exceptions where
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the final rules provide that the
surrender amounts specified in the
August 1 notice may be revised, the
final rules require the Administrator to
set a new surrender deadline for any
additional surrender required and to
transfer allowances back out of the
assurance account involved for any
reduced surrender requirement, as
appropriate.
Under the final rules (as under the
proposed rules), it is not a violation of
the CAA for total state covered-unit
emissions to exceed the state trading
budget with the variability limit or for
a group of owners and operators to
become subject to the allowance
surrender requirement under the
assurance provisions. However, the
failure of any group of owners and
operators to surrender the required
amount of allowances in the assurance
account created for such owners and
operators violates the CAA and is
subject to discretionary penalties, with
each required allowance that was not
surrendered and each day of the control
period involved constituting a violation.
(v) §§ 97.426 Through 97.428, 97.526
Through 97.528, 97.626 Through
97.628, and 97.726 Through 97.728—
Miscellaneous Provisions
These sections in the final rules (as in
the proposed rules) include provisions
allowing banking of the allowances
issued in the Transport Rule trading
programs, i.e., the retention of unused
Transport Rule allowances allocated for
a given control period for use or trading
in a later control period. While this can
potentially cause emissions from
sources in some states in some control
periods to be greater than the
allowances allocated for those control
periods, the assurance provisions limit
such emissions in a way that ensures
that each state’s significant contribution
to nonattainment and interference with
maintenance that EPA has identified in
this action will be eliminated.
These sections also include
provisions stating that the
Administrator can, at his or her
discretion and on his or her own
motion, correct any type of error that he
or she finds in an account in the
Allowance Management System. In
addition, the Administrator can review
any submission under the Transport
Rule trading programs, make
adjustments to the information in the
submission, and deduct or transfer
allowances based on such adjusted
information.
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(5) Emissions Monitoring,
Recordkeeping, and Reporting
Sections 97.430 through 97.435,
97.530 through 97.535, 97.630 through
97.635, and 97.730 through 97.735
establish emissions monitoring,
recordkeeping, and reporting
requirements for Transport Rule units.
These provisions reference the relevant
sections of Part 75 (40 CFR part 75),
where the specific procedures and
requirements for monitoring and
reporting NOX and SO2 mass emissions
are set forth. The provisions in the final
rules are virtually the same as the
monitoring, recordkeeping, and
reporting requirements in the proposed
rules and under previous EPAadministered trading programs, e.g., the
Acid Rain Program and NOX Budget and
CAIR trading programs. The final rule
provisions are also essentially the same
for each of the Transport Rule trading
programs, except for differences
reflecting the different pollutants and
control periods involved.
Under the provisions of the final rules
and under Part 75, a unit has several
options for monitoring and reporting. A
unit’s options are to use: a CEMS; an
excepted monitoring methodology (NOX
mass monitoring for certain peaking
units and SO2 mass monitoring for
certain oil- and gas-fired units); low
mass emissions monitoring for certain,
non-coal-fired, low emitting units; or an
alternative monitoring system approved
by the Administrator through a petition
process. In addition, unit owners and
operators may submit, and the
Administrator can approve, petitions for
alternatives to Transport Rule and Part
75 monitoring, recordkeeping, and
reporting requirements.
As discussed elsewhere in this
preamble, the final rules and Part 75
specify that each CEMS must undergo
rigorous initial certification testing and
periodic quality assurance testing
thereafter. In addition, when a
monitoring system is not operating
properly, standard substitute data
procedures are applied and result in a
conservative estimate of emissions for
the period involved. Further, the final
rules and Part 75 require electronic
submission, to the Administrator and in
a format prescribed by the
Administrator, of a quarterly emissions
report.
The final rules include revised
language in §§ 97.430(b)(3), 97.530(b)(3),
97.630(b)(3), and 97.730(b)(3) that
incorporates by reference, and thereby
applies to units in the Transport Rule
trading programs, clarification that EPA
recently adopted in § 75.4(e) of Part 75
(for Acid Rain Program units)
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concerning the requirements for
certification, recertification, and
diagnostic testing of emission
monitoring systems when a unit adds a
new stack or new add-on SO2 or NOX
emission control device. See 76 FR
17288, 17298–300 (March 28, 2011).
The revised language is adopted for the
reasons set forth in the preamble of that
Acid Rain Program final rule and in
order to continue the approach, in the
Transport Rule trading program rules, of
adopting monitoring, recordkeeping,
and reporting requirements that are
generally consistent with those in the
Acid Rain Program, which covers many
units in the Transport Rule trading
programs.
XII. Statutory and Executive Order
Reviews
The projected impacts of this final
rule as presented throughout the
preamble do not reflect minor technical
corrections to SO2 budgets in three
states (KY, MI, and NY) made after the
impact analyses were conducted. These
projections also assumed preliminary
variability limits that were smaller than
the variability limits finalized in this
rule. EPA conducted sensitivity analysis
confirming that these differences do not
meaningfully alter any of the Agency’s
findings or conclusions based on the
projected cost, benefit, and air quality
impacts presented for the final
Transport Rule. The results of this
sensitivity analysis are presented in
Appendix F in the final Transport Rule
RIA.
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A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
Under EO 12866 (58 FR 51735,
October 4, 1993), this action is an
‘‘economically significant regulatory
action’’ because it is likely to have an
annual effect on the economy of $100
million or more or adversely affect in a
material way the economy, a sector of
the economy, productivity, competition,
jobs, the environment, public health or
safety, or state, local, or tribal
governments or communities.
Accordingly, EPA submitted this
action to the OMB for review under EO
12866 and EO 13563 (76 FR 3821,
January 21, 2011) and any changes in
response to OMB recommendations
have been documented in the docket for
this action. In addition, EPA prepared
an analysis of the potential costs and
benefits for this action. This analysis is
contained in the Regulatory Impact
Analysis (RIA) for this action. For more
information on the costs and benefits for
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this rule, please refer to Table VIII.C–3
of this preamble.
When estimating the human health
benefits and compliance costs in Table
VIII.C–3 of this preamble, EPA applied
methods and assumptions consistent
with the state-of-the-science for human
health impact assessment, economics,
and air quality analysis. EPA applied its
best professional judgment in
performing this analysis and believes
that these estimates provide a
reasonable indication of the expected
benefits and costs to the nation of this
rulemaking. The RIA available in the
docket describes in detail the empirical
basis for EPA’s assumptions and
characterizes the various sources of
uncertainties affecting the estimates
below. In doing what is laid out above
in this paragraph, EPA adheres to EO
13563, ‘‘Improving Regulation and
Regulatory Review,’’ (76 FR 3,821,
January 21, 2011), which is a
supplement to EO 12866.
In addition to estimating costs and
benefits, EO 13563 focuses on the
importance of a ‘‘regulatory system
[that] * * * promote[s] predictability
and reduce[s] uncertainty’’ and that
‘‘identify[ies] and use[s] the best, most
innovative, and least burdensome tools
for achieving regulatory ends.’’ EO
13563 also states that ‘‘[i]n developing
regulatory actions and identifying
appropriate approaches, each agency
shall attempt to promote such
coordination, simplification, and
harmonization. Each agency shall also
seek to identify, as appropriate, means
to achieve regulatory goals that are
designed to promote innovation.’’ We
recognize that the utility sector has
compliance obligations related to
multiple environmental statutes
authorizing regulatory action, including
this rule’s requirements to reduce
interstate transport of harmful ozone
and fine particles and their precursors,
as well as other rules’ requirements to
reduce air toxic emissions, to reduce
greenhouse gas emissions, to safely
manage coal combustion wastes, and to
protect aquatic wildlife from water
intake procedures. In the wake of
promulgating this final rule, EPA
recognizes that moving forward the
agency needs to approach these
rulemakings in ways that allow the
industry to make practical investment
decisions that minimize costs in
complying with all of the final rules,
while still securing the fundamentally
important environmental and public
health benefits that led Congress to
enact those authorities in the first place.
At the same time, EPA notes that the
flexibility inherent in the allowancetrading mechanism included in this rule
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48343
affords utilities themselves a degree of
latitude to determine how best to
integrate compliance with the emission
reduction requirements of this rule and
those of the other rules.
The final rule will also reduce
emissions of directly emitted PM and
ozone precursors, and estimates of the
PM2.5-related benefits of these air
quality improvements may be found in
Tables VIII.C–1 and VIII.C–2 of this
preamble. When characterizing
uncertainty in the PM-mortality
relationship, EPA has historically
presented a sensitivity analysis applying
alternate assumed thresholds in the PM
concentration-response relationship. In
its synthesis of the current state of the
PM science, EPA’s 2009 Integrated
Science Assessment for Particulate
Matter concluded that a no-threshold
log-linear model most adequately
portrays the PM-mortality
concentration-response relationship. In
the RIA accompanying this rulemaking,
rather than segmenting out impacts
predicted to be associated levels above
and below a ‘‘bright line’’ threshold,
EPA includes a ‘‘lowest measured level’’
(LML) analysis that illustrates the
increasing uncertainty that characterizes
exposure attributed to levels of PM2.5
below the LML of each epidemiological
study used to estimate PM2.5-related
premature death. Figures provided in
the RIA show the distribution of
baseline exposure to PM2.5, as well as
the lowest air quality levels measured in
each of the epidemiology cohort studies.
This information provides a context for
considering the likely portion of PMrelated mortality benefits occurring
above or below the LML of each study;
in general, our confidence in the size of
the estimated reduction PM2.5-related
premature mortality diminishes as
baseline concentrations of PM2.5 are
lowered. Approximately 69 percent of
the avoided impacts occur at or above
an annual mean PM2.5 level of 10 μg/m3
(the LML of the Laden et al. 2006 study);
about 96 percent occur at or above an
annual mean PM2.5 level of 7.5 μg/m3
(the LML of the Pope et al. 2002 study).
Although the LML analysis provides
some insight into the level of
uncertainty in the estimated PM
mortality benefits, EPA does not view
the LML as a threshold and continues to
quantify PM-related mortality impacts
using a full range of modeled air quality
concentrations. It is important to note
that the monetized benefits include
many but not all health effects
associated with PM2.5 exposure. Benefits
are shown as a range from Pope, et al.,
(2002) to Laden, et al., (2006). These
models assume that all fine particles,
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regardless of their chemical
composition, are equally potent in
causing premature mortality because
there is no clear scientific evidence that
would support the development of
differential effects estimates by particle
type.
The cost analysis is also subject to
uncertainties. Estimating the cost
conversion from one process to another
is more difficult than estimating the cost
of adding control equipment because it
is more dependent on plant specific
information. More information on the
cost uncertainties can be found in the
RIA.
A summary of the monetized benefits
and net benefits for the final rule at
discount rates of 3 percent and 7
percent is in Table VIII.C–3 of this
preamble. For more information on the
benefits analysis, please refer to the RIA
for this rulemaking, which is available
in the docket.
B. Paperwork Reduction Act
EPA is required to document the
information collection burden imposed
by the Transport Rule on industry,
states, and EPA in an information
collection request (ICR). The ICR
describes the information collection
requirements associated with the
Transport Rule and estimates the
incremental costs of compliance with all
such requirements, such as the
requirement for industry to monitor,
record, and report emission data to EPA.
The ICR for the final Transport Rule
has been submitted for approval by
OMB under the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq., and the
information collection requirements it
documents are not enforceable until
such approval has been granted. An ICR
was also submitted to OMB in support
of the proposed Transport Rule; no
adverse comment was received by EPA
on either the information collection
requirements or their associated cost
estimates as described in that document.
The costs associated with the
information collection requirements of
the Transport Rule include start-up and
capital costs for units newly affected by
an emission trading program, or whose
reporting status has changed (e.g., from
ozone-season-only to annual reporting),
as well as the additional operation and
maintenance costs for Transport Ruleaffected units already participating in an
EPA-administered cap and trade
program. More information on the ICR
analysis is included in the final
Transport Rule docket.
The records and reports generated by
these activities will be used by EPA and
states to ensure that affected facilities
comply with emission limits and other
requirements. Such records and reports
are also helpful to EPA and states in
both identifying affected facilities that
may not be in compliance with
applicable requirements and in
discerning which units and what
records or processes should be
inspected.
The incremental capital and operating
costs associated with the recordkeeping
and reporting burden to Transport Ruleaffected sources in states participating
in the Transport Rule trading programs
are approximately $26 million annually
in 2010 dollars. The total number of
burden hours associated with the
recordkeeping and reporting burden to
Transport Rule-affected sources in states
participating in the Transport Rule
trading programs is approximately
185,000 hours annually. These estimates
include the annualized cost of installing
and operating appropriate SO2 and NOX
emission monitoring equipment to
measure and report the total emissions
of these pollutants from affected EGUs
(serving generators greater than 25 MW).
The burden to state and local air
agencies, as documented in the ICR,
includes any necessary SIP revisions,
performance of monitor certifications,
and fulfillment of audit responsibilities.
Burden is defined at 5 CFR 1320.3(b).
The amendments do not require any
notifications or reports beyond those
required by the General Provisions. The
recordkeeping requirements require
only the specific information needed to
determine compliance, which is
specifically authorized by CAA section
114 (42 U.S.C. 7414). All information
submitted to EPA for which a claim of
confidentiality is made will be
safeguarded according to EPA policies
in 40 CFR part 2, subpart B,
Confidentiality of Business Information.
An Agency may not conduct or sponsor,
and a person is not required to respond
to a collection of information unless it
displays a currently valid OMB control
number. The OMB control numbers for
EPA’s regulations in 40 CFR are listed
in 40 CFR part 9. When this ICR is
approved by OMB, the Agency will
publish a technical amendment to 40
CFR part 9 in the Federal Register to
display the OMB control number for the
approved information collection
requirements contained in this final
rule.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA)
generally requires an agency to prepare
a regulatory flexibility analysis of any
rule subject to notice and comment
rulemaking requirements under the
Administrative Procedure Act or any
other statute unless the agency certifies
that the rule will not have a significant
economic impact on a substantial
number of small entities. Small entities
include small businesses, small
organizations, and small governmental
jurisdictions.
For purposes of assessing the impacts
of this final rule on small entities, small
entity is defined as:
(1) A small business as defined by the
Small Business Administration’s (SBA)
regulations at 13 CFR 121.201. For the
electric power generation industry, the
small business size standard is an
ultimate parent entity defined as having
a total electric output of 4 million
megawatt-hours (MWh) or less in the
previous fiscal year.
(2) A small governmental jurisdiction
that is a government of a city, county,
town, school district or special district
with a population of less than 50,000;
and
(3) A small organization that is any
not-for-profit enterprise which is
independently owned and operated and
is not dominant in its field.
TABLE XII.C–1—POTENTIALLY REGULATED CATEGORIES AND ENTITIES a
NAICS code b
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Category
Industry ...............................................
Federal Government ..........................
State/Local Government ....................
Tribal Government .............................
221112
c 221112
2c 21112
921150
Examples of potentially regulated entities
Fossil-fuel-fired
Fossil-fuel-fired
Fossil-fuel-fired
Fossil-fuel-fired
electric
electric
electric
electric
utility
utility
utility
utility
steam
steam
steam
steam
generating
generating
generating
generating
units.
units owned by the federal government.
units owned by municipalities.
units in Indian Country.
a Include
NAICS categories for source categories that own and operate electric generating units only.
American Industry Classification System.
c Federal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged.
b North
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EPA used Velocity Suite’s Ventyx
data as a basis for identifying plant
ownership and compiling the list of
potentially affected small entities. For
plants burning fossil fuel as the primary
fuel, plant-level boiler and generator
capacity, heat input, generation, and
emission data were aggregated by owner
and then parent company. For
cooperatives, investor-owned utilities,
and subdivisions that generate less than
4 billion kWh of electricity annually but
may be part of a large entity, additional
research on power sales, operating
revenues, and other business activities
was performed to make a final
determination regarding size.
After considering the economic
impacts of this final rule on small
entities, EPA certifies that this action
will not have a significant economic
impact on a substantial number of small
entities (No SISNOSE). This
certification is based on the economic
impact of this final rule to all affected
small entities across all industries
affected. EPA assessed the potential
impact of this action on small entities
and found that there are about 660
potentially affected small units (i.e.,
greater than 25 MW and generating less
than 4 million MWh) out of 3,625
existing units in the Transport Rule
states. The majority of these EGUs are
owned by entities that do not meet the
small entity definition. The remaining
271 of the 660 EGUs are owned by 108
potentially affected small entities and
are likely to be affected by this rule.
EPA estimates that 24 of the 108
identified small entities will have
annualized costs greater than 1 percent
of their revenues, and the other 84 are
projected to incur costs less than 1
percent of revenues. Eleven small
entities out of 108—approximately 10
percent—are estimated to have
annualized costs greater than 3 percent
of their revenues. EPA has lessened the
impacts for small entities by excluding
all units smaller than 25 MWe. This
exclusion, in addition to the exemptions
for cogeneration units and solid waste
incineration units, eliminates the
burden of higher costs for a substantial
number of small entities located in the
Transport Rule states.
While the total number of small
entities has increased compared to the
proposal as a result of updated
modeling and changes in geographic
coverage, the number with compliance
costs greater than 1 percent of revenues
has fallen, and both the number and
percentage of significantly impacted
small entities (costs greater than 3
percent of revenues) are lower—now 10
percent compared to 17 percent in the
proposal. The share of significantly
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impacted small entities has fallen
because of updated modeling and the
change in the allowance allocation
methodology (see section VII.D for more
information about allowance
allocations).
Although this final rule will not have
a significant economic impact on a
substantial number of small entities,
EPA nonetheless has tried to reduce the
impact of this rule on small entities. In
EPA’s modeling, most of the cost
impacts for these small entities and
their associated units are driven by
lower electricity generation relative to
the base case. Specifically, two small
units reduce their generation by
significant amounts, driving the bulk of
the costs for all small entities. Excluding
these two units, one of the main drivers
of small entity impacts is higher fuel
costs, which the affected units would
incur irrespective of whether they had
to comply with this rule. In addition,
EPA’s decision to exclude units smaller
than 25 MWe has already significantly
reduced the burden on approximately
390 small entities.
For more information on the small
entity impacts associated with the final
rule, refer to the Regulatory Impact
Analysis for this final rule, which can
be found in the docket for this rule and
on the Web site https://www.epa.gov/
airtransport.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates
Reform Act of 1995 (UMRA), 2 U.S.C.
1531–1538, requires federal agencies,
unless otherwise prohibited by law, to
assess the effects of their regulatory
actions on state, local, and tribal
governments, and the private sector.
This rule contains a federal mandate
that may result in expenditures of $100
million or more for state, local, and
tribal governments, in the aggregate, or
the private sector in any 1 year.
Accordingly, EPA has prepared, under
section 202 of the UMRA, a written
statement which is summarized later.
Consistent with the intergovernmental
consultation provisions of section 204 of
the UMRA, EPA held consultations with
the governmental entities affected by
this rule during the proposal phase.
Subsequently, EPA sent a letter to the
ten Representative National
Organizations to draw their attention to
the Transport Rule Notice of Data
Availability (NODA) on allowance
allocations and other related matters
and to invite their comments. During
the NODA comment period, EPA
participated in informational calls with
the Environmental Council of the States
(ECOS) and the National Governors
Association to provide information
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about the NODA directly to state and
local officials. There were no new
concerns raised during these
informational calls. In addition, EPA
also conducted consultations with
federally recognized tribes prior to
finalizing this rule and invited them to
comment on the allowance allocation
NODA. EPA has added a new unit setaside provision to this final rule
specifically for EGUs constructed in
Indian country to ensure allowances are
available to tribes and tribal sovereignty
is respected.
Consistent with section 205, EPA
identified and considered a reasonable
number of regulatory alternatives. In the
proposal, EPA included three remedy
options that it considered when
developing this final rule: (1) The
preferred remedy trading programs, (2)
State Budgets/Intrastate Trading, and (3)
Direct Controls. Moreover, section 205
allows EPA to adopt an alternative other
than the least costly, most cost-effective,
or least burdensome alternative if the
Administrator publishes with the final
rule an explanation why that alternative
was not adopted.
EPA examined the potential economic
impacts on state- and municipalityowned entities associated with this
rulemaking based on assumptions of
how the affected states will implement
control measures to meet program
requirements. Although EPA does not
conclude that the requirements of the
UMRA apply to the Transport Rule,
these impacts have been calculated to
provide additional understanding of the
nature of potential impacts and
additional information.
EPA has determined that this rule
contains a federal mandate that may
result in expenditures of $100 million or
more in 1 year. EPA has determined that
this rule contains no regulatory
requirements that might significantly or
uniquely affect small governments and
that development of a small government
plan under section 203 of the Act is not
required. The costs of compliance will
be borne predominately by sources in
the private sector although a small
number of sources owned by state and
local governments may also be
impacted. The requirements in this
action do not distinguish EGUs based on
ownership, either for those units that
are included within the scope of the
rule or for those units that are exempted
by the generating capacity cut-off.
Therefore, this rule is not subject to the
requirements of section 203 of UMRA
because it contains no regulatory
requirements that might significantly or
uniquely affect small governments.
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E. Executive Order 13132: Federalism
This final rule does not have
federalism implications. It will not have
substantial direct effects on the states,
on the relationship between the national
government and the states, or on the
distribution of power and
responsibilities among the various
levels of government, as specified in
Executive Order 13132. The final rule
primarily affects private industry, and
does not impose significant economic
costs on state or local governments.
Thus, Executive Order 13132 does not
apply to the final rule.
Although section 6 of Executive Order
13132 does not apply to the final rule,
EPA did provide information to state
and local officials during development
of both the proposal and final rule. EPA
sent a letter to the ten Representative
National Organizations to draw their
attention to the Transport Rule NODA
on allowance allocations and other
related matters and to invite their
comments. Following that letter in early
2011, EPA participated in informational
calls with the Environmental Council of
the States (ECOS) and the National
Governors Association to provide
information about the NODA directly to
state and local officials. There were no
new concerns raised during these
informational calls.
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F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
Under Executive Order 13175 (65 FR
67249, November 9, 2000), EPA may not
issue a regulation that has tribal
implications, that imposes substantial
direct compliance costs, and that is not
required by statute, unless the federal
government provides the funds
necessary to pay the direct compliance
costs incurred by tribal governments, or
EPA consults with tribal officials early
in the process of developing the
proposed regulation and develops a
tribal summary impact statement.
EPA has concluded that this action
may have tribal implications if a new
unit covered by the rule is built in
Indian country. Additionally, tribes
have a vested interest in how this final
rule affects their air quality. However, it
will neither impose substantial direct
compliance costs on tribal governments,
nor preempt tribal law. EPA consulted
with tribal officials during the process
of finalizing this regulation to permit
them to have meaningful and timely
input into its development.
EPA received comments on the
proposed Transport Rule that the
Agency did not properly conduct
consultation during the proposal phase
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of the rulemaking process. In response
to these comments, EPA sent a letter to
all federally-recognized tribes in the
country offering consultation. In
addition, several commenters also noted
that the Agency did not adequately
consider opportunities for tribes to enter
into any of the trading programs and, in
particular, did not consider sovereignty
issues when addressing how to
distribute allowances to potential new
units in Indian country. On January 7,
2011, EPA issued a NODA requesting
comment on allocations for new units in
Indian country, among other topics.
The Agency held a consultation call
with three tribes on January 21, 2011. A
follow-up call was held on February 4,
2011 with two of the three original
tribes plus 13 additional tribes, as well
as representatives from the National
Tribal Air Association. In all ten tribes
participated in these calls as
consultation and six participated as
information-sharing. EPA considered
the additional input from these
consultation and information calls, in
conjunction with the public comments,
in the development of the final rule.
Accordingly, EPA created an Indian
country new unit set-aside to
specifically address tribes’ concerns
regarding the protection of tribal
sovereignty in the distribution of
allowances for new units in Indian
country. See section VII.D.2 of this
preamble for details on the Indian
country set-aside for new units
constructed in Indian country within
states covered by the Transport Rule.
As required by section 7(a) of the
Executive Order, EPA’s Tribal
Consultation Official has certified that
the requirements of the Executive Order
have been met in a meaningful and
timely manner. A copy of the
certification is included in the docket
for this action.
G. Executive Order 13045: Protection of
Children From Environmental Health
and Safety Risks
Executive Order 13045 (62 FR 19,885,
April 23, 1997) applies to any rule that:
(1) Is determined to be ‘‘economically
significant’’ as defined under EO 12866,
and (2) concerns an environmental
health or safety risk that EPA has reason
to believe may have a disproportionate
effect on children. If the regulatory
action meets both criteria, the Agency
must evaluate the environmental health
or safety effects of this planned rule on
children, and explain why this planned
regulation is preferable to other
potentially effective and reasonably
feasible alternatives considered by the
Agency.
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This action is not subject to Executive
Order 13045 because it does not involve
decisions on environmental health or
safety risks that may disproportionately
affect children. EPA believes that the
emission reductions from the strategies
in this rule will further improve air
quality and will further improve
children’s health. Analyses by EPA that
show how the emission reductions from
the strategies in this rule will further
improve air quality and children’s
health can be found in the RIA for this
rule.
H. Executive Order 13211: Actions That
Significantly Affect Energy Supply,
Distribution, or Use
Executive Order 13211 (66 FR 28355,
May 22, 2001) provides that agencies
shall prepare and submit to the
Administrator of the Office of
Regulatory Affairs, OMB, a Statement of
Energy Effects for certain actions
identified as ‘‘significant energy
actions.’’ Section 4(b) of Executive
Order 13211 defines ‘‘significant energy
action’’ as ‘‘any action by an agency
(normally published in the Federal
Register) that promulgates or is
expected to lead to the promulgation of
a final rule or regulation, including
notices of inquiry, advance notices of
proposed rulemaking, and notices of
proposed rulemaking: (1)(i) That is a
significant regulatory action under
Executive Order 12866 or any successor
order, and (ii) is likely to have a
significant adverse effect on the supply,
distribution, or use of energy; or (2) that
is designated by the Administrator of
the Office of Information and Regulatory
Affairs as a significant energy action.’’
This rule is a significant regulatory
action under Executive Order 12866,
and this rule is likely to have a
significant adverse effect on the supply,
distribution, or use of energy. EPA
prepared a Statement of Energy Effects
for this action as follows.
Under the provisions of this rule, EPA
projects that approximately 4.8 GW of
additional coal-fired generation may be
removed from operation by 2014. In
practice, however, the units projected to
be uneconomic to maintain may be
‘‘mothballed,’’ retired, or kept in service
to ensure transmission reliability in
certain parts of the grid. These units are
predominantly small and infrequentlyused generating units dispersed
throughout the area affected by the rule.
If current forecasts of either natural gas
prices or electricity demand were
revised in the future to be higher, that
would create a greater incentive to keep
these units operational.
EPA estimates that average retail
electricity prices could increase in the
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contiguous U.S. by about 1.7 percent in
2012 and 0.8 percent in 2014. This is
generally less of an increase than often
occurs with fluctuating fuel prices and
other market factors. Related to this,
EPA projects limited impacts on coal
and gas prices. The average delivered
coal price decreases by about 1.4
percent in 2012 and 0.9 percent in 2014
relative to the base case as a result of
decreased coal demand and shifts in the
type of coal demanded. EPA also
projects that the electric power sectordelivered natural gas price will increase
by about 0.3 percent over the 2012–2030
timeframe and that natural gas use for
electricity generation will increase by
approximately 200 billion cubic feet
(BCF) by 2014. These impacts are well
within the range of price variability that
is regularly experienced in natural gas
markets. Finally, under the Transport
Rule, EPA projects that coal production
for use by the power sector will increase
above 2009 levels by 21 million tons in
2012 and a further 14 million tons in
2014, as opposed to 30 million tons in
2012 and a further 26 million tons in
2014 without the Transport Rule in
place. The Transport Rule is not
projected to impact production of coal
for uses outside the power sector (e.g.,
export, industrial sources), which
represent approximately 6 percent of
total coal production in 2009. EPA does
not believe that this rule will have any
other impacts (e.g., on oil markets) that
exceed the significance criteria.
EPA believes that a number of
features of the rulemaking serve to
reduce its impact on energy supply.
First, the trading component of the
Transport Rule provides flexibility to
the power sector and enables industry to
comply with the emission reduction
requirements in the most cost-effective
manner compared to the alternative
remedy approaches on which EPA took
comment in the proposal, thus
minimizing overall costs and the
ultimate impact on energy supply.
Second, the more stringent budgets for
SO2 are set in two phases, providing
adequate time for EGUs to install
pollution controls. In addition, both the
operational flexibility of trading and the
ability to bank allowances for future
years helps industry plan for and ensure
reliability in the electrical system.
For more details concerning energy
impacts, see the RIA for the Transport
Rule.
I. National Technology Transfer
Advancement Act
Section 12(d) of the National
Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104–
113, 12(d) (15 U.S.C. 272 note) directs
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EPA to use voluntary consensus
standards in its regulatory activities
unless to do so would be inconsistent
with applicable law or otherwise
impractical. Voluntary consensus
standards are technical standards (e.g.,
materials specifications, test methods,
sampling procedures, and business
practices) that are developed or adopted
by voluntary consensus standards
bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations
when the Agency decides not to use
available and applicable voluntary
consensus standards. This rule will
require all sources to meet the
applicable monitoring requirements of
40 CFR part 75. Part 75 already
incorporates a number of voluntary
consensus standards. Consistent with
the Agency’s Performance Based
Measurement System (PBMS), Part 75
sets forth performance criteria that
allow the use of alternative methods to
the ones set forth in Part 75. The PBMS
approach is intended to be more flexible
and cost effective for the regulated
community; it is also intended to
encourage innovation in analytical
technology and improved data quality.
At this time, EPA is not recommending
any revisions to Part 75; however, EPA
periodically revises the test procedures
set forth in Part 75. When EPA revises
the test procedures set forth in Part 75
in the future, EPA will address the use
of any new voluntary consensus
standards that are equivalent. Currently,
even if a test procedure is not set forth
in Part 75, EPA is not precluding the use
of any method, whether it constitutes a
voluntary consensus standard or not, as
long as it meets the performance criteria
specified; however, any alternative
methods must be approved through the
petition process under 40 CFR 75.66
before they are used.
J. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
Executive Order (EO) 12898 (59 FR
7629 (Feb. 16, 1994)) establishes federal
executive policy on environmental
justice. Its main provision directs
federal agencies, to the greatest extent
practicable and permitted by law, to
make environmental justice part of their
mission by identifying and addressing,
as appropriate, disproportionately high
and adverse human health or
environmental effects of their programs,
policies, and activities on minority, lowincome, and Tribal populations in the
United States. During development of
this final Transport Rule, EPA
considered its impacts on low-income,
minority, and tribal communities in
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several ways and provided multiple
opportunities for these communities to
meaningfully participate in the
rulemaking process. The proposed
Transport Rule included an analysis of
its effects on these populations; this
section describes additional analysis
conducted since proposal, EPA’s
responses to key comments on
environmental justice issues raised
during the comment period, and the
public outreach and comment
opportunities for this rule.
A summary of the history, statutory
authority, and key components of this
final Transport Rule are described in the
Executive Summary (section III) of this
preamble. That section also summarizes
a supplemental notice of proposed
rulemaking (SNPR) that EPA is
publishing to correct a procedural flaw
by providing an opportunity for public
comment on issues that arose from new
analyses with updated inventories and
modeling platforms.
Briefly, this final Transport Rule will
reduce emissions of SO2 and NOX in 23
eastern and central states in 2012 and
2014 that contribute to annual and/or
24-hour PM2.5 nonattainment or
interfere with maintenance in
downwind states. It will also reduce
emissions of ozone-season NOX in 20
eastern and central states in 2012 and
2014 that contribute to the 1997 ozone
nonattainment or interfere with
maintenance in downwind states. This
rule is replacing an earlier rule (the
2005 Clean Air Interstate Rule (CAIR))
that was first vacated and then
remanded to EPA by the U.S. Court of
Appeals for the District of Columbia
Circuit in 2008.
1. Consideration of Environmental
Justice in the Transport Rule
Development Process and Response to
Comments
The effects of this final Transport
Rule on the most highly exposed
populations were integral in its
development. This rule uses EPA’s
authority in CAA section 110(a)(2)(d) to
reduce sulfur dioxide (SO2) and
(nitrogen oxides) NOX pollution that
significantly contributes to downwind
PM2.5 and ozone nonattainment or
maintenance areas. As a result, the rule
will reduce exposures to ozone and
PM2.5 in the most-contaminated areas
(i.e., areas that are not meeting the 1997
ozone and 1997 and 2006 PM2.5
National Ambient Air Quality Standards
(NAAQS)). In addition, the rule
separately identifies both nonattainment
areas and maintenance areas
(maintenance areas are those that are
projected to meet the NAAQS but that,
based on past data, are in danger of
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exceeding the standards in the future).
This requirement reduces the likelihood
that any areas close to the level of the
standard will exceed the current healthbased standards in the future.
This final Transport Rule implements
these emission reductions using an
emission trading mechanism with
assurance provisions for power plants.
EPA recognizes that many
environmental justice communities
have voiced concerns in the past about
emission trading and the potential for
any emission increases in any location.
EPA also received several comments on
this issue during the comment period
for the proposed Transport Rule. As
described below, we believe this final
rule addresses the concerns raised on
this issue during the comment period.
PM2.5 and ozone pollution from power
plants have both local and regional
components: Part of the pollution in a
given location—even in locations near
emission sources—is due to emissions
from nearby sources and part is due to
emissions that travel hundreds of miles
and mix with emissions from other
sources. Therefore, in many instances
the exact location of the upwind
reductions does not affect the levels of
air pollution downwind.
It is important to note that the section
of the Clean Air Act providing authority
for this rule, section 110(a)(2)(D), unlike
some other provisions, does not dictate
levels of control for particular facilities.
As at least one commenter noted, none
of the alternatives put forward by EPA
in the proposed rule could have ensured
no emission increases at any facility.
Under the direct control alternative, the
emission rate for each facility would
have been limited but each facility
could emit more by increasing their
power output in order to meet
electricity reliability or other goals.
Under the intrastate trading option,
sources could not trade allowances with
sources in other states but individual
facilities within each state could have
increased their emissions as long as
another facility in the state had
decreased theirs at some time.
The final Transport Rule allows
sources to trade allowances with other
sources in the same or different states
while firmly constraining any emissions
shifting that may occur by requiring a
strict emission ceiling in each state (the
budget plus variability limit). In
addition, assurance provisions in the
rule outline the allowance surrender
penalties for failing to meet the budget
plus variability limits; there are
additional allowance penalties as well
as financial penalties for failing to hold
an adequate number of allowances to
cover emissions. This approach
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eliminates emissions in each state that
significantly contribute to downwind
nonattainment or maintenance areas,
while allowing power companies to
adjust generation as needed and ensure
that the country’s electricity needs will
continue to be met. EPA maintains that
the existence of these assurance
provisions, including the penalties
imposed when triggered, will ensure
that state emissions will stay below the
level of the budget plus variability limit.
In addition, all sources must hold
enough allowances to cover their
emissions. Therefore, if a source emits
more than its allocation in a given year,
either another source must have used
less than its allocation and be willing to
sell some of its excess allowances, or the
source itself had emitted less than its
allocation in one or more previous years
(i.e., banked allowances for future use).
In summary, the final remedy
addresses commenter concerns about
localized hot spots and reduces ambient
concentrations of pollution where they
are most needed by sensitive and
vulnerable populations by: Considering
the science of ozone and PM2.5 transport
to set strict state budgets to eliminate
significant contributions to ozone and
PM2.5 nonattainment and maintenance
(i.e., the most polluted) areas;
implementing air quality-assured
trading; requiring any emissions above
the level of the allocations to be offset
by emission decreases; and imposing
strict penalties for sources that
contribute to a state’s exceedance of its
budget plus variability limit. In
addition, it is important to note that
nothing in this final rule allows sources
to violate their title V permit or any
other federal, state, or local emissions or
air quality requirements.
EPA received comments from several
tribal commenters regarding the lack of
allocations in the proposal to new units
in Indian Country. EPA responded to
these comments by changing the
allocation approach in the final rule to
create Indian country new unit setasides. In order to protect tribal
sovereignty, these set-asides will be
managed and distributed by the federal
government regardless of whether the
Transport Rule in the adjoining or
surrounding state is implemented
through a FIP or SIP. While there are no
existing power plants in Indian country
covered by this Transport Rule, the
Indian country set-asides will ensure
that any future new units built in Indian
country will be able to get the necessary
allowances. A full discussion of the
Indian country new unit set-asides can
be found in section VII.D.2.
EPA also received several comments
during the comment period from
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individuals and groups requesting
additional emission reductions to
further protect sensitive and vulnerable
communities. While EPA has adjusted
the emission requirements somewhat in
the final rule to accommodate revised
data and updated modeling results, we
are finalizing emission reductions very
similar to the level in the proposal. This
is because EPA believes that the
emission reductions required by this
final rule are appropriate to meet the
statutory requirements of CAA section
110(a)(2)(d) and respond to the concerns
raised by the Court’s opinion in North
Carolina that remanded CAIR to the
Agency in 2008.
In addition, it is important to note
that CAA section 110(a)(2)(d), which
addresses transport of criteria pollutants
between states, is only one of many
provisions of the CAA that provide EPA,
states, and local governments with
authorities to reduce exposure to ozone
and PM2.5 in communities. These legal
authorities work together to reduce
exposure to these pollutants in
communities, including for minority,
low-income, and tribal populations, and
provide substantial health benefits to
both the general public and sensitive
sub-populations.
For example, the recently-proposed
Mercury and Air Toxics Standards
(MATS) would also result in significant
reductions in SO2 emissions and
provide significant health and
environmental benefits nationwide.
This and other actions described in
section III will have substantial and
long-term effects on both the U.S. power
industry and on communities currently
breathing dirty air. Therefore, we
anticipate significant interest in many, if
not most, of these actions from
environmental justice communities,
among many others. EPA will continue
to provide multiple opportunities for
comment on these actions, similar to the
opportunities provided during the
comment process for this rule, detailed
at the end of this section. We encourage
environmental justice communities to
review and comment on these actions.
2. Potential Environmental and Public
Health Impacts Among Populations
Susceptible or Vulnerable to Air
Pollution
EPA expects that this final rule will
provide significant health and
environmental benefits to, among
others, people with asthma, people with
heart disease, and people living in
ozone or PM2.5 nonattainment areas.
EPA’s analysis of the effects of this rule,
including information on air quality
changes and the resulting health
benefits, is presented both in section
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VIII of this preamble and in the
Regulatory Impact Analysis (RIA) for
this rule. These documents can be
accessed through the rule docket No.
EPA–HQ–OAR–2009–0491 and from the
main EPA webpage for the rule at
https://www.epa.gov/airtransport.
EPA considered several aspects of the
effects of the Transport Rule on
minority, low-income, and tribal
populations. These included: amount of
emission reductions and where they
take place (including any potential for
areas of increased emissions); the
changes in ambient concentrations
across the affected area; the estimated
health benefits; and how the estimated
health benefits are distributed among
different populations, including those
susceptible and vulnerable to air
pollution health impacts.
a. Emission Reductions
EPA’s emission modeling data
indicate that implementation of the
Transport Rule will substantially reduce
SO2 emissions from electric generating
units (EGUs). As noted in section III,
emissions in states covered by the
Transport Rule will decrease by 6.4
million tons (73 percent) in 2014
compared to 2005 (the year the Clean
Air Interstate Rule was finalized).
Emissions are also projected to decrease
when compared to the base case (the
base case estimates emissions in 2014 in
the absence of this rule or the Clean Air
Interstate Rule it is replacing). EPA
estimates that SO2 emissions in 2014 in
covered states will be 3.9 million tons
lower (62 percent lower) compared to
the base case.
EPA also assessed emission changes
in states not covered by the Transport
Rule. Emissions in the states not
covered by the Transport Rule are also
projected to decrease substantially
compared to 2005 levels; in 2014 SO2
emissions are projected to be
approximately 430,000 tons lower (30
percent lower) than in 2005.
As described in section VI.C, EPA’s
modeling does project that some states
not covered by any of the fine particle
control programs in the final Transport
Rule may experience increases of SO2
emissions greater than 5,000 tons
compared to the base case. These states
are Arkansas, Colorado, Louisiana,
Montana, and Wyoming. These
emission increases are the result of
forecasted changes in operation of
power plant units outside of the
Transport Rule states due to the
interconnected nature of the utility grid
(i.e., shifts in generation of electricity to
sources outside the Transport Rule
states) or influence of the rule on the
market for lower sulfur coal. For
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example, EPA projects that the rule will
raise demand for lower sulfur coal in
the states covered by the Transport Rule
for PM2.5 (thereby raising its price),
which may lead sources in states not
covered for PM2.5 to choose highersulfur coals that increase SO2 emissions
in those states.
EPA is not requiring SO2 emission
reductions in these states under this
rule because our modeling indicates
none of these states’ contributions
would increase enough to cause them to
meet or exceed the thresholds described
in section V.D for either of the PM2.5
standards. EPA’s authority under CAA
section 110(a)(2)(d) is limited to
addressing this significant contribution
to nonattainment and interference with
maintenance. However, as noted above,
EPA has recently proposed the Mercury
and Air Toxics Standards that will
apply nationwide and result in
substantial additional SO2 emission
reductions, including in states not
covered by the Transport Rule.
EPA’s emission modeling data
indicates that ozone-season NOX
emissions from EGUs in states covered
by the Transport Rule will be
approximately 340,000 tons lower (36
percent lower) in 2014 than they were
in 2005. Emissions in states not covered
by the Transport Rule are also expected
to decrease somewhat (approximately
82,000 tons or 25 percent). EPA’s
modeling does project that two states
(California and Pennsylvania) may
experience increases of NOX emissions
greater than 5,000 tons in 2014
compared to 2005 levels. California is
not covered by the Transport Rule; in
Pennsylvania, 2005 was an unusually
low-emitting year and sources are
projected to increase their heat input
slightly (usually meaning they are
generating more power) after the rule
takes effect.
EPA also assessed the expected
changes in seasonal NOX emissions with
implementation of the Transport Rule
compared to the base case (i.e., without
the rule) in 2014. The modeling
indicates ozone-season NOX emissions
from EGUs in both covered states and
non-Transport Rule states under this
rule will be lower than they would have
been in 2014 in the base case. Ozoneseason NOX emissions in covered states
are projected to decrease by
approximately 74,000 tons (11 percent);
ozone-season NOX emissions in nonTransport Rule states are projected to
decrease by approximately 10,000 tons
(4 percent). Both California and
Pennsylvania are projected to have
lower NOX emissions in 2014 under the
Transport Rule as compared to the base
case. In addition, EPA anticipates that
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additional upcoming actions, including
likely additional interstate transport
reductions to help states attain the
upcoming new ozone NAAQS, will
result in significant additional NOX
reductions in the future.
b. Air Quality Improvements
EPA assessed the air quality metrics
(called ‘‘design values’’) for each
NAAQS addressed in this rule: 24-hour
PM2.5, annual PM2.5, and ozone. We
then compared these metrics for the
final rule to the same metrics in the
recent past (2003–2007 average ambient
air quality) and for the 2014 base case
to assess improvements in air quality.
EPA’s modeling indicates that there
will be significant improvements in air
quality as measured by the 24-hour
PM2.5 standard. Throughout much of the
eastern half of the U.S., 24-hour PM2.5
design values are projected to improve
more than 10 μg/m3 compared to the
2003–2007 average levels. In addition,
compared to the 2014 base case levels,
we project the Transport Rule will result
in improvements of 8–10 μg/m3 in a
broad swath of states stretching from far
southwestern New York through
Pennsylvania, Ohio, West Virginia,
Maryland, Indiana, southern Illinois,
eastern Missouri, eastern Arkansas,
Kentucky, Tennessee, northern
Alabama, and northern Mississippi.
Isolated areas of Virginia and northern
New Jersey are also expected to see this
level of improvement. Improvements of
2–6 μg/m3 are projected in surrounding
states stretching from New England and
New York to Minnesota, Iowa, the far
eastern edge of Nebraska, Missouri,
eastern Kansas, Oklahoma, Texas, the
Gulf of Mexico states, and the states
bordering the Atlantic Ocean from
Florida to New Hampshire.
EPA modeling indicates that air
quality as measured by the annual PM2.5
design value will also improve.
Improvements range from 2 to over 4
μg/m3 compared to the 2003–2007
average levels throughout the eastern
half of the U.S. Annual PM2.5 air quality
with the Transport Rule is also
projected to improve compared to the
2014 base case levels. The largest
improvements of up to 4 μg/m3 are
projected to occur in northern West
Virginia and a small area in
northwestern Tennessee. Improvements
of up to 3 μg/m3 are projected for
portions of the Ohio River valley areas
of southwestern Pennsylvania, Ohio,
West Virginia, Kentucky, central
Tennessee, and southern Indiana.
Improvements of up to 2 μg/m3 are
projected to take place in a ring of
surrounding states including all or most
of New York, Michigan, Indiana,
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Illinois, Missouri, Arkansas, the far
eastern edge of Oklahoma, the
northeastern edge of Texas, Louisiana,
Mississippi, Alabama, Georgia, South
Carolina, North Carolina, Virginia,
Maryland, Delaware, Pennsylvania, and
New Jersey. Smaller improvements are
projected in New England, Wisconsin,
the Plains states, southeastern New
Mexico, and Florida.
EPA modeling indicates that ozone air
quality will improve greatly (10–12 ppb
or more) across much of the eastern U.S.
between the average levels seen in
2003–2007 and implementation of the
Transport Rule. Most of the
improvements take place in the base
case; that is, they are the result of
federal and state programs other than
the Transport Rule. However, ozone air
quality is projected to improve
somewhat as a direct result of the
Transport Rule. Improvements in ozone
design values compared to the base case
of more than 1 ppb are projected for
portions of Florida, eastern Oklahoma,
and areas along the upper reaches of the
Ohio River. In addition, improvements
in ozone design values of up to 1 ppb
are projected over a wide area across the
eastern U.S. from New England to Texas
and north to Minnesota. Improvements
are also projected in north-central
Colorado.
EPA’s modeling does indicate small
increases in annual PM2.5 air quality
design values in the final rule compared
to the 2014 base case in two counties
outside of the Transport Rule states: one
county in northern Colorado and one
county in eastern Montana. As noted
above in the section on emissions, these
increases are likely the result of
forecasted changes in electricity
generation due to the interconnected
nature of both the utility grid and the
national low-sulfur coal market. It
should be noted that 2003–2007 average
air quality levels in these counties are
well below the level of the NAAQS. In
addition, other actions, including
federal rules such as the recently
proposed Mercury and Air Toxics
Standards, state, or local actions may
also improve air quality in these areas
over the next few years.
As described in section VIII.B, EPA
anticipates that this final rule will
reduce, but not eliminate, the number of
nonattainment and maintenance areas
for the 1997 ozone and PM2.5 and 2006
PM2.5 NAAQS. As noted above, ozone
and PM2.5 concentrations are the result
of both local emissions and long-range
transport of pollution. Even when the
significant contributions of upwind
states are fully eliminated, additional
emission reductions within the
nonattainment area and/or the
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downwind state will be needed for some
areas to attain and maintain the
NAAQS.
c. Estimated Health Benefits
This rule reduces concentrations of
PM2.5 and ozone pollution. Exposure to
these pollutants can cause, or contribute
to, adverse health effects that affect
many minority, low-income, and tribal
individuals and communities. PM2.5 and
ozone are particularly (but not
exclusively) harmful to children, the
elderly, and people with existing heart
and lung diseases, including asthma.
Exposure to these pollutants can cause
premature death and trigger heart
attacks, asthma attacks in those with
asthma, chronic and acute bronchitis,
emergency room visits and
hospitalizations, as well as milder
illnesses that keep children home from
school and adults home from work.
High rates of heart disease (e.g., high
blood pressure) 123 and asthma 124 exist
in many environmental justice
communities, making these populations
more susceptible to air pollution health
impacts. In addition, many individuals
in these communities lack access to
high quality health care to treat these
illnesses.125
We estimate that in 2014 the PMrelated annual benefits of the final rule
include approximately 13,000 to 34,000
fewer premature mortalities, 8,700 fewer
cases of chronic bronchitis, 15,000
fewer non-fatal heart attacks, 8,500
fewer hospitalizations (for respiratory
and cardiovascular disease combined),
10 million fewer days of restricted
activity due to respiratory illness, and
approximately 1.7 million fewer lost
work days. We also estimate substantial
health improvements for children in the
form of fewer cases of upper and lower
respiratory illness, acute bronchitis, and
asthma attacks.
Ozone health-related benefits are
expected to occur during the summer
ozone season (usually ranging from May
to September in the eastern U.S.). Based
upon modeling for 2014, annual ozone
related health benefits are expected to
include (in addition to the PM-related
benefits above) between 27–120 fewer
premature mortalities, 240 fewer
123 Neighborhood of Residence and Incidence of
Coronary Heart Disease Ana V. Diez Roux, M.D.,
PhD et al. N Engl J Med 2001; 345:99–106; July 12,
2001.
124 Centers for Disease Control and Prevention.
2007 National Health 11. Interview Survey Data.
Table 4–1. Current Asthma Prevalence Percents by
Age, United States: National Health Interview
Survey, 2007. Atlanta, GA: U.S. Department of
Health and Human Services, CDC, 2010. Accessed
June 1, 2010.
125 R. Nelson, Eds. National Institute of Medicine,
2003.
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hospital admissions for respiratory
illnesses in children and older adults,
86 fewer emergency room admissions
for asthma, 160,000 fewer days with
restricted activity levels, and 51,000
fewer ‘‘school absence’’ days when
children are absent from school due to
illnesses. When adding the PM and
ozone-related mortalities together, we
find that the final rule will yield
between 13,000 and 34,000 fewer
premature mortalities.
It should be noted that, as discussed
in the RIA, there are other benefits to
the emission reductions discussed here,
including many other health benefits
beyond reducing the risk of premature
mortality. Additional benefits of
reducing emissions of SO2 include
improved visibility, reduced
acidification of lakes and streams, and
reduced mercury methylation in
contaminated waters; additional
benefits of NOX reductions include
improved visibility, reduced
acidification of lakes and streams, and
reduced coastal eutrophication.
d. Distribution of Health Benefits
Among Different Populations
EPA also estimated the PM2.5
mortality risks according to race,
income, and educational attainment
before and after implementation of this
Transport Rule. We used premature
mortality for this analysis for several
reasons: It is the most serious health
effect of exposure to PM2.5, and EPA has
access to nationwide incidence and
demographic data at an appropriate
scale to conduct this type of analysis.
EPA included educational attainment in
this assessment because research on the
effects of PM2.5 has found that
educational attainment is inversely
related to the risk of all-cause mortality.
That is, populations with lower levels of
education (in particular, less than grade
12) experience higher rates of PM2.5
mortality. Krewski and colleagues 126
note in their analysis of this relationship
that the level of education attainment is
likely to be a surrogate for the effects of
complex socioeconomic processes
(including factors such as race and
income) on mortality.
In the first step of the analysis, we
estimated baseline (2005) PM2.5
mortality risk by race (White, Black,
Asian, Native American) among people
living in the counties with the highest
(top 5 percent) PM2.5 mortality risk. We
126 Krewski D, Jerrett M, Burnett RT, Ma R,
Hughes E, Shi Y, Turner C, Pope CA, Thurston G,
Calle EE, Thunt MJ. Extended follow-up and spatial
analysis of the American Cancer Society study
linking particulate air pollution and mortality. HEI
Research Report, 140, 2009; Health Effects Institute,
Boston, MA.
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also estimated baseline PM2.5 mortality
risk by race among people living in the
counties with both the highest (top 5
percent) poverty rate and the highest
(top 5 percent) PM2.5 mortality risk in
2005. And, we estimated the baseline
(2005) PM2.5 mortality risk by
educational attainment for people living
in the highest PM2.5 mortality risk
counties. In the second step, we
estimated the changes in risk for
different races among the people living
in these ‘‘high-risk’’ and ‘‘high risk and
high-poverty’’ counties resulting from
implementation of other existing rules
in 2014 and from implementation of just
the Transport Rule in 2014. Finally, in
the third step, we compared the effects
of the Transport Rule by race in the
high-risk and high risk/high-poverty
counties with the effects on people (by
race) living in all other counties.
In 2005, people living in the highestrisk counties and in the high risk/high
poverty counties had substantially
greater risks of PM2.5-related death than
people living in the other 95 percent of
counties. This was true regardless of
race: The difference among races in both
groups of counties was very small and
dwarfed by the large difference between
the two groups of counties for all races.
For educational attainment, in contrast,
our analysis found that people with less
than high school education had
significantly greater risks from PM2.5
mortality than people with a greater
than high school education. This was
especially true for people living in the
highest-risk counties, but also held true
for people living in all other counties.
In summary, in 2005, having less than
a high school or high school education,
living in one of the poorest counties,
and living in a high air pollution risk
county are associated with higher PM2.5
mortality risk; race is not.
Our analysis of the effects of the
Transport Rule on this underlying
exposure pattern finds that the rule will
significantly reduce the PM2.5 mortality
among all populations of different races
living throughout the U.S. compared to
both 2005 and 2014 pre-rule (i.e., base
case) levels. No group will experience
any increases in PM2.5 related deaths as
a result of implementing the Transport
Rule.
The analysis indicates that the
populations with the largest
improvement (i.e., largest decline) in
PM2.5 mortality risk as a result of the
Transport Rule in 2014 (compared to the
base case in 2014) are people living in
the highest-risk counties. Among these
counties, the largest improvements are
for people with less than high school or
high school education. These reductions
in risk within the highest-risk counties,
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as well as the reductions in risk within
the other 95 percent of counties, are
distributed among populations of
different races fairly evenly. Therefore,
there is no indication that people of
particular race receive a greater benefit
(or smaller benefit) than others.
The analysis indicates that people
living in the high risk/high poverty
counties will experience larger
improvements in risk from the
Transport Rule compared to their
counterparts in the other counties. This
result suggests that the Transport Rule
is providing the greatest risk reduction
improvements among counties
containing the poorest, and highest risk,
populations. There is also little
difference in the improvement in risk
among races; in other words, people in
the high risk/high poverty counties
experience the same improvement in
risk regardless of race.
The analysis also indicates that this
rule, in conjunction with the
implementation of existing or proposed
rules (e.g., the proposed Mercury and
Air Toxics Standards), will reduce the
disparity in risk between the highestrisk counties and the other 95 percent
of counties for all races and educational
levels. In addition, implementation of
this Transport Rule and other rules will,
together, reduce risks in the poorest and
highest risk counties to the approximate
level of risk for the rest of the counties
before implementation. This analysis is
presented in more detail in the RIA for
this rule which is available in the rule
docket No. EPA–HQ–OAR–2009–0491
and from the main EPA webpage for the
rule at https://www.epa.gov/airtransport.
3. Meaningful Public Participation
EPA defines ‘‘Environmental Justice’’
to include meaningful involvement of
all people regardless of race, color,
national origin, or income with respect
to the development, implementation,
and enforcement of environmental laws,
regulations, and policies. To promote
meaningful involvement, EPA
developed a communication and
outreach strategy to ensure that
interested communities had access to
the proposed Transport Rule, were
aware of its content, and had an
opportunity to comment during the
comment period. These efforts are
summarized below.
As EPA began considering approaches
to address the court remand of the 2005
Clean Air Interstate Rule, long before
the rule was proposed, the agency also
began gathering input from a large range
of stakeholders. In the spring of 2009,
EPA held a series of listening sessions
to gather information and perspectives
from stakeholders prior to the formal
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48351
start of the rulemaking process. These
stakeholders included a number of
environmental groups who requested
that EPA consider several potential
environmental justice issues during
development of this rule. In addition,
many environmental justice
organizations were represented at a
November 2009 EPA-Health and Human
Services White House Stakeholder
Briefing titled, ‘‘The Public Health
Benefits of Energy Reform’’ in which
EPA discussed our intention to propose
this rule in the spring of 2010 and
participants had the opportunity to
respond. Finally, EPA notified Indian
Tribes of our intent to propose this rule
in the fall of 2009 during a regularly
scheduled meeting to update the
National Tribal Air Association
members of upcoming EPA policies and
regulations and to receive input from
them on the effects of these efforts in
Indian country. These were not
opportunities for stakeholders to
comment on the specifics of the
proposal, as they took place prior to its
development, but they provided
valuable information that EPA used in
developing the proposal.
Just after the rule was proposed in
July 2010, EPA presented a summary of
information related to the proposed
Transport Rule at the National
Environmental Justice Advisory Council
(NEJAC) meeting in Washington, DC,
and responded to questions from NEJAC
members regarding the proposed rule.
EPA also solicited suggestions for how
to engage environmental justice
communities during the rule comment
period.
During the public comment period,
EPA held public hearings in Chicago,
Philadelphia, and Atlanta. Each hearing
was advertised by EPA through a variety
of products targeted to general
audiences (e.g., fact sheets, press
release, slide presentation, etc.); on
EPA’s environmental justice listserve;
and by non-profit organizations (e.g.,
American Lung Association). The public
hearings were held in public buildings
(i.e., no formal identification required to
enter or to speak) and were open for
11 hours (9 a.m.–8 p.m.) to
accommodate commenters with various
work schedules. All three hearings were
well-attended by members of the general
public. During hearing breaks, EPA staff
spent time talking with individuals,
including those representing
environmental justice organizations or
communities, to understand their
perspectives in greater detail. As noted
above, several commenters at each
hearing made comments related to the
need to protect communities living near
power plants and the most vulnerable
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individuals. Some of these commenters
specifically mentioned environmental
justice; others mentioned issues often of
concern to environmental justice
communities, such as hot spots, interest
in additional emission reductions and
greater environmental protection, and
concern over the effects of the rule on
the most sensitive and vulnerable
populations.
In September 2010, during the
comment period, EPA held a webinar
for EJ communities on the proposed
Transport Rule. A presentation tailored
for an audience of environmental
justice, community, and tribal
representatives was specifically
designed for this webinar. It was sent to
registered participants beforehand and
put on the Transport Rule webpage,
where it remains posted. The
presentation included both information
on the context of the rule, plain
language information describing the rule
itself, and directions on how to
comment on the rule.
EPA staff made a short presentation
and answered questions about the
Transport Rule on a standing bimonthly community conference call
targeted to environmental justice and
tribal representatives and organizations.
In addition, at the fall 2010 NEJAC
meeting in Kansas City, Missouri, EPA
provided details of the proposed
Transport Rule as part of a larger
discussion of a sector-based approach to
utility regulation.
Regarding tribal consultation, EPA
sent letters to all 565 federallyrecognized Tribes in the country
offering consultation on the proposed
Transport Rule. In addition, the January
7 NODA on allowance allocation
methodologies specifically requested
comment on allocating allowances to
new units in Indian Country. EPA held
two consultation and informationsharing calls with 16 interested Tribes
in late January and early February 2011.
Tribes participating on these
consultation and information calls
provided comments on the proposed
rule and the allowance allocation
NODA. As noted above, this additional
input from the consultation process was
taken into account in the development
of the final rule. See Section XII.F for
more information on tribal consultation.
4. Summary
EPA believes that the vast majority of
communities and individuals in areas
covered by this rule, including
numerous low-income, minority, and
tribal individuals and communities in
both rural areas and inner cities in the
eastern and central U.S., will see
significant improvements in air quality
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and resulting improvements in health.
EPA’s assessment of the effects of the
proposed and final Transport Rules on
these communities included: (a) The
structure of the rule and responses to
comments received on issues specific to
these communities; (b) expected SO2
and NOX emission reductions; (c)
expected PM2.5 and ozone air quality
improvements; (d) expected health
benefits, including asthma and other
health effects of particular concern for
environmental justice communities; and
(e) a quantitative assessment of the
expected socioeconomic distribution of
a key health benefit (reduction in
premature mortality). All of these
analyses indicate large health and
environmental benefits for these
communities; none shows evidence of
adverse effects. As a result, EPA
concludes that we do not expect
disproportionately high and adverse
human health or environmental effects
on minority, low-income, or tribal
populations in the United States as a
result of implementing this final
Transport Rule.
K. Congressional Review Act
The Congressional Review Act, 5
U.S.C. 801 et seq., as added by the Small
Business Regulatory Enforcement
Fairness Act of 1996, generally provides
that before a rule may take effect, the
agency promulgating the rule must
submit a rule report, which includes a
copy of the rule, to each House of the
Congress and to the Comptroller General
of the United States. EPA will submit a
report containing this rule and other
required information to the U.S. Senate,
the U.S. House of Representatives, and
the Comptroller General of the United
States prior to publication of the rule in
the Federal Register. A major rule
cannot take effect until 60 days after it
is published in the Federal Register.
This action is a ‘‘major rule’’ as defined
by 5 U.S.C. 804(2). This rule will be
effective October 7, 2011.
L. Judicial Review
Petitions for judicial review of this
action must be filed in the United States
Court of Appeals for the District of
Columbia Circuit by October 7, 2011.
Section 307(b)(1) of the CAA indicates
which Federal Courts of Appeal have
venue for petitions of review of final
actions by EPA. This section provides,
in part, that petitions for review must be
filed in the Court of Appeals for the
District of Columbia Circuit if (i) the
agency action consists of ‘‘nationally
applicable regulations promulgated, or
final action taken, by the
Administrator,’’ or (ii) such action is
locally or regionally applicable, if ‘‘such
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action is based on a determination of
nationwide scope or effect and if in
taking such action the Administrator
finds and publishes that such action is
based on such a determination.’’
Any final action related to the
Transport Rule is ‘‘nationally
applicable’’ within the meaning of
section 307(b)(1). Through this rule,
EPA interprets section 110 of the CAA,
a provision which has nationwide
applicability. In addition, the Transport
Rule applies to 27 States. The Transport
Rule is also based on a common core of
factual findings and analyses
concerning the transport of pollutants
between the different states subject to it.
For these reasons, the Administrator
also is determining that any final action
regarding the Transport Rule is of
nationwide scope and effect for
purposes of section 307(b)(1). Thus,
pursuant to section 307(b) any petitions
for review of final actions regarding the
Transport Rule must be filed in the
Court of Appeals for the District of
Columbia Circuit within 60 days from
the date final action is published in the
Federal Register.
Filing a petition for reconsideration of
this action does not affect the finality of
this rule for the purposes of judicial
review nor does it extend the time
within which a petition for judicial
review may be filed and shall not
postpone the effectiveness of such rule
or action. In addition, pursuant to CAA
section 307(b)(2) this action may not be
challenged later in proceedings to
enforce its requirements.
In addition, this action is subject to
the provisions of section 307(d). CAA
section 307(d)(1)(B) provides that
section 307(d) applies to, among other
things, to ‘‘the promulgation or revision
of an implementation plan by the
Administrator under CAA section
110(c)’’ (42 U.S.C. 7407(d)(1)(B)). The
Agency has complied with procedural
requirements of CAA section 307(d)
during the course of this rulemaking.
List of Subjects
40 CFR Part 51
Administrative practice and
procedure, Air pollution control,
Incorporation by reference,
Intergovernmental relations, Nitrogen
oxides, Ozone, Particulate matter,
Regional haze, Reporting and
recordkeeping requirements, Sulfur
dioxide.
40 CFR Part 52
Administrative practice and
procedure, Air pollution control,
Incorporation by reference,
Intergovernmental relations, Nitrogen
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oxides, Ozone, Particulate matter,
Regional haze, Reporting and
recordkeeping requirements, Sulfur
dioxide.
40 CFR Part 72
Acid rain, Administrative practice
and procedure, Air pollution control,
Electric utilities, Incorporation by
reference, Intergovernmental relations,
Nitrogen oxides, Reporting and
recordkeeping requirements, Sulfur
dioxide.
40 CFR Part 78
Acid rain, Administrative practice
and procedure, Air pollution control,
Electric utilities, Intergovernmental
relations, Nitrogen oxides, Reporting
and recordkeeping requirements, Sulfur
dioxide.
40 CFR Part 97
Administrative practice and
procedure, Air pollution control,
Electric utilities, Nitrogen oxides,
Reporting and recordkeeping
requirements, Sulfur dioxide.
Dated: July 6, 2011.
Lisa P. Jackson,
Administrator.
For the reasons set forth in the
preamble, parts 51, 52, 72, 78, and 97
of chapter I of title 40 of the Code of
Federal Regulations are amended as
follows:
PART 51—[AMENDED]
1. The authority citation for part 51
continues to read as follows:
■
Authority: 23 U.S.C. 101; 42 U.S.C. 7401–
7671q.
§ 51.121
[Amended]
2. In § 51.121 paragraph (r)(2) is
amended by removing the words
‘‘§ 51.123(bb)’’ and adding, in their
place, the words ‘‘§ 51.123(bb) with
regard to an ozone season that occurs
before January 1, 2012’’.
■ 3. Section 51.123 is amended by
adding a new paragraph (ff) to read as
follows:
■
§ 51.123 Findings and requirements for
submission of State implementation plan
revisions relating to emissions of oxides of
nitrogen pursuant to the Clean Air Interstate
Rule.
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*
*
*
*
*
(ff) Notwithstanding any provisions of
paragraphs (a) through (ee) of this
section, subparts AA through II and
AAAA through IIII of part 96 of this
chapter, subparts AA through II and
AAAA through IIII of part 97 of this
chapter, and any State’s SIP to the
contrary:
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(1) With regard to any control period
that begins after December 31, 2011, the
Administrator:
(i) Rescinds the determination in
paragraph (a) of this section that the
States identified in paragraph (c) of this
section must submit a SIP revision with
respect to the fine particles (PM2.5)
NAAQS and the 8-hour ozone NAAQS
meeting the requirements of paragraphs
(b) through (ee) of this section; and
(ii) Will not carry out any of the
functions set forth for the Administrator
in subparts AA through II and AAAA
through IIII of part 96 of this chapter,
subparts AA through II and AAAA
through IIII of part 97 of this chapter, or
in any emissions trading program
provisions in a State’s SIP approved
under this section;
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any
year thereafter;
(3) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Allowance Tracking System
accounts all CAIR NOX allowances
allocated for a control period in 2012
and any subsequent year, and,
thereafter, no holding or surrender of
CAIR NOX allowances will be required
with regard to emissions or excess
emissions for such control periods; and
(4) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Ozone Season Allowance
Tracking System accounts all CAIR NOX
Ozone Season allowances allocated for
a control period in 2012 and any
subsequent year, and, thereafter, no
holding or surrender of CAIR NOX
Ozone Season allowances will be
required with regard to emissions or
excess emissions for such control
periods.
■ 4. Section 51.124 is amended by
adding a new paragraph (s) to read as
follows:
§ 51.124 Findings and requirements for
submission of State implementation plan
revisions relating to emissions of sulfur
dioxide pursuant to the Clean Air Interstate
Rule.
*
*
*
*
*
(s) Notwithstanding any provisions of
paragraphs (a) through (r) of this
section, subparts AAA through III of
part 96 of this chapter, subparts AAA
through III of part 97 of this chapter,
and any State’s SIP to the contrary:
(1) With regard to any control period
that begins after December 31, 2011, the
Administrator:
(i) Rescinds the determination in
paragraph (a) of this section that the
States identified in paragraph (c) of this
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48353
section must submit a SIP revision with
respect to the fine particles (PM2.5)
NAAQS meeting the requirements of
paragraphs (b) through (r) of this
section; and
(ii) Will not carry out any of the
functions set forth for the Administrator
in subparts AAA through III of part 96
of this chapter, subparts AAA through
III of part 97 of this chapter, or in any
emissions trading program in a State’s
SIP approved under this section; and
(2) The Administrator will not deduct
for excess emissions any CAIR SO2
allowances allocated for 2012 or any
year thereafter.
§ 51.125
[Reserved]
5. Section 51.125 is removed and
reserved.
■
PART 52—[AMENDED]
6. The authority citation for part 52
continues to read as follows:
■
Authority: 42 U.S.C. 7401, et seq.
Subpart A—General Provisions
7. Section 52.35 is amended by adding
a new paragraph (f) to read as follows:
■
§ 52.35 What are the requirements of the
Federal Implementation Plans (FIPs) for the
Clean Air Interstate Rule (CAIR) relating to
emissions of nitrogen oxides?
*
*
*
*
*
(f) Notwithstanding any provisions of
paragraphs (a) through (d) of this
section, subparts AA through II and
AAAA through IIII of part 97 of this
chapter, and any State’s SIP to the
contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions in paragraphs (a)
through (d) of this section relating to
NOX annual or ozone season emissions
shall not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AA through II
and AAAA through IIII of part 97 of this
chapter;
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any
year thereafter;
(3) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Allowance Tracking System
accounts all CAIR NOX allowances
allocated for a control period in 2012
and any subsequent year, and,
thereafter, no holding or surrender of
CAIR NOX allowances will be required
with regard to emissions or excess
emissions for such control periods; and
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(4) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Ozone Season Allowance
Tracking System accounts all CAIR NOX
Ozone Season allowances allocated for
a control period in 2012 and any
subsequent year, and, thereafter, no
holding or surrender of CAIR NOX
allowances will be required with regard
to emissions or excess emissions for
such control periods.
■ 8. Section 52.36 is amended by adding
a new paragraph (e) to read as follows:
§ 52.36 What are the requirements of the
Federal Implementation Plans (FIPs) for the
Clean Air Interstate Rule (CAIR) relating to
emissions of sulfur dioxide?
*
*
*
*
*
(e) Notwithstanding any provisions of
paragraphs (a) through (c) of this
section, subparts AAA through III of
part 97 of this chapter and any State’s
SIP to the contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions of paragraphs (a)
through (e) of this section relating to
SO2 emissions shall not be applicable;
and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AAA through
III of part 97 of this chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR SO2
allowances allocated for 2012 or any
year thereafter.
■ 9. Sections §§ 52.38 and 52.39 are
added to subpart A to read as follows:
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§ 52.38 What are the requirements of the
Federal Implementation Plans (FIPs) under
the Transport Rule (TR) relating to
emissions of nitrogen oxides?
(a)(1) The TR NOX Annual Trading
Program provisions set forth in subpart
AAAAA of part 97 of this chapter
constitute the TR Federal
Implementation Plan provisions that
relate to annual emissions of nitrogen
oxides (NOX).
(2) The provisions of subpart AAAAA
of part 97 of this chapter apply to the
sources in the following States and
Indian country located within the
borders of such States: Alabama,
Georgia, Illinois, Indiana, Iowa, Kansas,
Kentucky, Maryland, Michigan,
Minnesota, Missouri, Nebraska, New
Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina,
Tennessee, Texas, Virginia, West
Virginia, and Wisconsin.
(3) Notwithstanding the provisions of
paragraph (a)(1) of this section, a State
listed in paragraph (a)(2) of this section
may adopt and include in a SIP
revision, and the Administrator will
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Jkt 223001
approve, as TR NOX Annual allowance
allocation provisions replacing the
provisions in § 97.411(a) of this chapter
with regard to the State and the control
period in 2013, a list of TR NOX Annual
units and the amount of TR NOX
Annual allowances allocated to each
unit on such list, provided that the list
of units and allocations meets the
following requirements:
(i) All of the units on the list must be
units that are in the State and
commenced commercial operation
before January 1, 2010;
(ii) The total amount of TR NOX
Annual allowance allocations on the list
must not exceed the amount, under
§ 97.410(a) of this chapter for the State
and the control period in 2013, of TR
NOX Annual trading budget minus the
sum of the new unit set-aside and
Indian country new unit set-aside;
(iii) The list must be submitted
electronically in a format specified by
the Administrator; and
(iv) The SIP revision must not provide
for any change in the units and
allocations on the list after approval of
the SIP revision by the Administrator
and must not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
AAAAA of part 97 of this chapter;
(v) Provided that:
(A) By October 17, 2011, the State
must notify the Administrator
electronically in a format specified by
the Administrator of the State’s intent to
submit to the Administrator a complete
SIP revision meeting the requirements
of paragraph (a)(3)(i) through (iv) of this
section by April 1, 2012; and
(B) The State must submit to the
Administrator a complete SIP revision
described in paragraph (a)(3)(v)(A) of
this section by April 1, 2012.
(4) Notwithstanding the provisions of
paragraph (a)(1) of this section, a State
listed in paragraph (a)(2) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, regulations revising subpart
AAAAA of part 97 of this chapter as
follows and not making any other
substantive revisions of that subpart:
(i) The State may adopt, as TR NOX
Annual allowance allocation or auction
provisions replacing the provisions in
§§ 97.411(a) and (b)(1) and 97.412(a) of
this chapter with regard to the State and
the control period in 2014 or any
subsequent year, any methodology
under which the State or the permitting
authority allocates or auctions TR NOX
Annual allowances, and may adopt, in
addition to the definitions in § 97.402 of
this chapter, one or more definitions
that shall apply only to terms as used in
the adopted TR NOX Annual allowance
PO 00000
Frm 00148
Fmt 4701
Sfmt 4700
allocation or auction provisions, if such
methodology—
(A) Requires the State or the
permitting authority to allocate and, if
applicable, auction a total amount of TR
NOX Annual allowances for any such
control period not exceeding the
amount, under §§ 97.410(a) and 97.421
of this chapter for the State and such
control period, of the TR NOX Annual
trading budget minus the sum of the
Indian country new unit set-aside and
the amount of any TR NOX Annual
allowances already allocated and
recorded by the Administrator.
(B) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR NOX Annual allowances
for any such control period to any TR
NOX Annual units covered by
§ 97.411(a) of this chapter, that the State
or the permitting authority submit such
allocations or the results of such
auctions for such control period (except
allocations or results of auctions to such
units of TR NOX Annual allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator no later
than the following dates:
Year of the control
period for which TR
NOX annual allowances are allocated or
auctioned
Deadline for submission of allocations or
auction results to
administrator
2014 ..........................
2015 ..........................
2016 ..........................
2017 ..........................
2018 ..........................
2019 ..........................
2020 and any year
thereafter.
June 1, 2013.
June 1, 2013.
June 1, 2014.
June 1, 2014.
June 1, 2015.
June 1, 2015.
June 1 of the fourth
year before the
year of the control
period.
(C) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR NOX Annual allowances
for any such control period to any TR
NOX Annual units covered by
§§ 97.411(b)(1) and 97.412(a) of this
chapter, that the State or the permitting
authority submit such allocations or the
results of such auctions (except
allocations or results of auctions to such
units of TR NOX Annual allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator by July 1
of the year of such control period.
(D) Does not provide for any change,
after the submission deadlines in
paragraphs (a)(4)(i)(B) and (C) of this
section, in the allocations submitted to
the Administrator by such deadlines
and does not provide for any change in
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any allocation determined and recorded
by the Administrator under subpart
AAAAA of part 97 of this chapter;
(ii) Provided that the State must
submit a complete SIP revision meeting
the requirements of paragraph (a)(4)(i) of
this section by December 1 of the year
before the year of the deadlines for
submission of allocations or auction
results under paragraphs (a)(4)(i)(B) and
(C) of this section for the first control
period for which the State wants to
make allocations or hold an auction
under paragraph (a)(4)(i) of this section.
(5) Notwithstanding the provisions of
paragraph (a)(1) of this section, a State
listed in paragraph (a)(2) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, as correcting in whole or in
part, as appropriate, the deficiency in
the SIP that is the basis for the TR
Federal Implementation Plan set forth in
paragraphs (a)(1) through (4) of this
section, regulations that are
substantively identical to the provisions
of the TR NOX Annual Trading Program
set forth in §§ 97.402 through 97.435 of
this chapter, except that the SIP
revision:
(i) May adopt, as TR NOX Annual
allowance allocation or auction
provisions replacing the provisions in
§§ 97.411(a) and (b)(1) and 97.412(a) of
this chapter with regard to the State and
the control period in 2014 or any
subsequent year, any methodology
under which the State or the permitting
authority allocates or auctions TR NOX
Annual allowances and that—
(A) Requires the State or the
permitting authority to allocate and, if
applicable, auction a total amount of TR
NOX Annual allowances for any such
control period not exceeding the
amount, under §§ 97.410(a) and 97.421
of this chapter for the State and such
control period, of the TR NOX Annual
trading budget minus the sum of the
Indian country new unit set-aside and
the amount of any TR NOX Annual
allowances already allocated and
recorded by the Administrator.
(B) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR NOX Annual allowances
for any such control period to any TR
NOX Annual units covered by
§ 97.411(a) of this chapter, that the State
or the permitting authority submit such
allocations or the results of such
auctions for such control period (except
allocations or results of auctions to such
units of TR NOX Annual allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator no later
than the following dates:
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19:20 Aug 05, 2011
Jkt 223001
Year of the control
period for which TR
NOX annual allowances are allocated or
auctioned
Deadline for submission of allocations or
auction results to
administrator
2014 ..........................
2015 ..........................
2016 ..........................
2017 ..........................
2018 ..........................
2019 ..........................
2020 and any year
thereafter.
June 1, 2013.
June 1, 2013.
June 1, 2014.
June 1, 2014.
June 1, 2015.
June 1, 2015.
June 1 of the fourth
year before the
year of the control
period.
(C) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR NOX Annual allowances
for any such control period to any TR
NOX Annual units covered by
§§ 97.411(b)(1) and 97.412(a) of this
chapter, that the State or the permitting
authority submit such allocations or the
results of such auctions (except
allocations or results of auctions to such
units of TR NOX Annual allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator by July 1
of the year of such control period.
(D) Does not provide for any change,
after the submission deadlines in
paragraphs (a)(5)(i)(B) and (C) of this
section, in the allocations submitted to
the Administrator by such deadlines
and does not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
AAAAA of part 97 of this chapter;
(ii) May adopt, in addition to the
definitions in § 97.402 of this chapter,
one or more definitions that shall apply
only to terms as used in the TR NOX
Annual allowance allocation or auction
provisions adopted under paragraph
(a)(5)(i) of this section;
(iii) May substitute the name of the
State for the term ‘‘State’’ as used in
subpart AAAAA of part 97 of this
chapter, to the extent the Administrator
determines that such substitutions do
not make substantive changes in the
provisions in §§ 97.402 through 97.435
of this chapter; and
(iv) Must not include any of the
references to, or requirements imposed
on, any unit in Indian country within
the borders of the State in the provisions
in §§ 97.402 through 97.435 of this
chapter and must not include the
provisions in §§ 97.411(b)(2) and
97.412(b), all of which provisions will
continue to apply under the portion of
the TR Federal Implementation Plan
that is not replaced by the SIP revision;
(v) Provided that, if and when any
covered unit is located in Indian
PO 00000
Frm 00149
Fmt 4701
Sfmt 4700
48355
country within the borders of the State,
the Administrator may modify his or her
approval of the SIP revision to exclude
the provisions in §§ 97.402 (definitions
of ‘‘common designated representative’’,
‘‘common designated representative’s
assurance level’’, and ‘‘common
designated representative’s share’’),
97.406(c)(2), 97.425, and the portions of
other provisions referencing these
sections and may modify the portion of
the TR Federal Implementation Plan
that is not replaced by the SIP revision
to include these provisions;
(vi) Provided that the State must
submit a complete SIP revision meeting
the requirements of paragraphs (a)(5)(i)
through (iv) of this section by December
1 of the year before the year of the
deadlines for submission of allocations
or auction results under paragraphs
(a)(5)(i)(B) and (C) of this section
applicable to the first control period for
which the State wants to make
allocations or hold an auction under
paragraphs (a)(5)(i) and (ii) of this
section.
(6) Following promulgation of an
approval by the Administrator of a
State’s SIP revision as correcting in
whole or in part, as appropriate, the
SIP’s deficiency that is the basis for the
TR Federal Implementation Plan
described in paragraphs (a)(1) through
(5) of this section, the provisions of
paragraph (a)(2) of this section will no
longer apply to the sources in the State,
unless the Administrator’s approval of
the SIP revision is partial or conditional,
and will continue to apply to sources in
any Indian country within the borders
of the State.
(7) Notwithstanding the provisions of
paragraph (a)(6) of this section, if, at the
time of such approval of the State’s SIP
revision, the Administrator has already
started recording any allocations of TR
NOX Annual allowances under subpart
AAAAA of part 97 of this chapter to
units in a State for a control period in
any year, the provisions of subpart
AAAAA of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The TR NOX Ozone Season
Trading Program provisions set forth in
part 97 of this chapter constitute the TR
Federal Implementation Plan provisions
that relate to emissions of NOX during
the ozone season, defined as May 1
through September 30 of a calendar
year.
(2) The provisions of subpart BBBBB
of part 97 of this chapter apply to
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08AUR2
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
sources in each of the following States
and Indian country located within the
borders of such States: Alabama,
Arkansas, Florida, Georgia, Illinois,
Indiana, Kentucky, Louisiana,
Maryland, Mississippi, New Jersey, New
York, North Carolina, Ohio,
Pennsylvania, South Carolina,
Tennessee, Texas, Virginia, and West
Virginia.
(3) Notwithstanding the provisions of
paragraph (b)(1) of this section, a State
listed in paragraph (b)(2) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, as TR NOX Ozone Season
allowance allocation provisions
replacing the provisions in § 97.511(a)
of this chapter with regard to the State
and the control period in 2013, a list of
TR NOX Ozone Season units and the
amount of TR NOX Ozone Season
allowances allocated to each unit on
such list, provided that the list of units
and allocations meets the following
requirements:
(i) All of the units on the list must be
units that are in the State and
commenced commercial operation
before January 1, 2010;
(ii) The total amount of TR NOX
Ozone Season allowance allocations on
the list must not exceed the amount,
under § 97.510(a) of this chapter for the
State and the control period in 2013, of
TR NOX Ozone Season trading budget
minus the sum of the new unit set-aside
and Indian country new unit set-aside;
(iii) The list must be submitted
electronically in a format specified by
the Administrator; and
(iv) The SIP revision must not provide
for any change in the units and
allocations on the list after approval of
the SIP revision by the Administrator
and must not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
BBBBB of part 97 of this chapter;
(v) Provided that:
(A) By October 17, 2011, the State
must notify the Administrator
electronically in a format specified by
the Administrator of the State’s intent to
submit to the Administrator a complete
SIP revision meeting the requirements
of paragraph (b)(3)(i) through (iv) of this
section by April 1, 2012; and
(B) The State must submit to the
Administrator a complete SIP revision
described in paragraph (b)(3)(v)(A) of
this section by April 1, 2012.
(4) Notwithstanding the provisions of
paragraph (b)(1) of this section, a State
listed in paragraph (b)(2) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, regulations revising subpart
BBBBB of part 97 of this chapter as
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19:20 Aug 05, 2011
Jkt 223001
follows and not making any other
substantive revisions of that subpart:
(i) The State may adopt, as
applicability provisions replacing the
provisions in §§ 97.504(a)(1) and (2) of
this chapter, provisions substantively
identical to those provisions, except that
the words ‘‘more than 25 MWe’’ are
replaced, whenever such words appear,
by words specifying a uniform lower
limit on the amount of megawatts that
is not greater than the amount specified
by the words ‘‘more than 25 MWe’’ and
is not less than the amount specified by
the words ‘‘15 MWe or more’’; or
(ii) The State may adopt, as TR NOX
Ozone Season allowance allocation or
auction provisions replacing the
provisions in §§ 97.511(a) and (b)(1) and
97.512(a) of this chapter with regard to
the control period in 2014 or any
subsequent year, any methodology
under which the State or the permitting
authority allocates or auctions TR NOX
Ozone Season allowances, and may
adopt, in addition to the definitions in
§ 97.502 of this chapter, one or more
definitions that shall apply only to
terms as used in the adopted TR NOX
Ozone Season allowance allocation or
auction provisions, if such
methodology—
(A) Requires the State or the
permitting authority to allocate and, if
applicable, auction a total amount of TR
NOX Ozone Season allowances for any
such control period not exceeding the
amount, under §§ 97.510(a) and 97.521
of this chapter for the State and such
control period, of the TR NOX Ozone
Season trading budget minus the sum of
the Indian country new unit set-aside
and the amount of any TR NOX Ozone
Season allowances already allocated
and recorded by the Administrator.
(B) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR NOX Ozone Season
allowances for any such control period
to any TR NOX Ozone Season units
covered by § 97.511(a) of this chapter,
that the State or the permitting authority
submit such allocations or the results of
such auctions for such control period
(except allocations or results of auctions
to such units of TR NOX Ozone Season
allowances remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator no later
than the following dates:
Year of the control
period for which TR
NOX Ozone Season
allowances are allocated or auctioned
2014 ..........................
2015 ..........................
PO 00000
Frm 00150
Fmt 4701
Deadline for submission of allocations or
auction results to
administrator
June 1, 2013.
June 1, 2013.
Sfmt 4700
Year of the control
period for which TR
NOX Ozone Season
allowances are allocated or auctioned
2016 ..........................
2017 ..........................
2018 ..........................
2019 ..........................
2020 and any year
thereafter.
Deadline for submission of allocations or
auction results to
administrator
June 1, 2014.
June 1, 2014.
June 1, 2015.
June 1, 2015.
June 1 of the fourth
year before the
year of the control
period.
(C) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR NOX Ozone Season
allowances for any such control period
to any TR NOX Ozone Season units
covered by §§ 97.511(b)(1) and 97.512(a)
of this chapter, that the State or the
permitting authority submit such
allocations or the results of such
auctions (except allocations or results of
auctions to such units of TR NOX Ozone
Season allowances remaining in a setaside after completion of the allocations
or auctions for which the set-aside was
created) to the Administrator by July 1
of the year of such control period.
(D) Does not provide for any change,
after the submission deadlines in
paragraphs (b)(4)(ii)(B) and (C) of this
section, in the allocations submitted to
the Administrator by such deadlines
and does not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
BBBBB of part 97 of this chapter;
(iii) Provided that the State must
submit a complete SIP revision meeting
the requirements of paragraph (b)(4)(i)
or (ii) of this section by December 1 of
the year before the year of the deadlines
for submission of allocations or auction
results under paragraphs (b)(4)(ii)(B)
and (C) of this section applicable to the
first control period for which the State
wants to replace the applicability
provisions, make allocations, or hold an
auction under paragraph (b)(4)(i) or (ii)
of this section.
(5) Notwithstanding the provisions of
paragraph (b)(1) of this section, a State
listed in paragraph (b)(2) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, as correcting in whole or in
part, as appropriate, the deficiency in
the SIP that is the basis for the TR
Federal Implementation Plan set forth in
paragraphs (b)(1) through (4) of this
section, regulations that are
substantively identical to the provisions
of the TR NOX Ozone Season Trading
Program set forth in §§ 97.502 through
97.535 of this chapter, except that the
SIP revision:
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(i) May adopt, as applicability
provisions replacing the provisions in
§§ 97.504(a)(1) and (2) of this chapter,
provisions substantively identical to
those provisions, except that the words
‘‘more than 25 MWe’’ are replaced,
whenever such words appear, by words
specifying a uniform lower limit on the
amount of megawatts that is not greater
than the amount specified by the words
‘‘more than 25 MWe’’ and is not less
than the amount specified by the words
‘‘15 MWe or more’’; or
(ii) May adopt, as TR NOX Ozone
Season allowance allocation provisions
replacing the provisions in §§ 97.511(a)
and (b)(1) and 97.512(a) of this chapter
with regard to the control period in
2014 and any subsequent year, any
methodology under which the State or
the permitting authority allocates
auctions TR NOX Ozone Season
allowances and that—
(A) Requires the State or the
permitting authority to allocate and, if
applicable, auction a total amount of TR
NOX Ozone Season allowances for any
such control period not exceeding the
amount, under §§ 97.510(a) and 97.521
of this chapter for the State and such
control period, of the TR NOX Ozone
Season trading budget minus the sum of
the Indian country new unit set-aside
and the amount of any TR NOX Ozone
Season allowances already allocated
and recorded by the Administrator.
(B) Requires, to the extent the State
adopts provisions for allocations or
auction of TR NOX Ozone Season
allowances for any such control period
to any TR NOX Ozone Season units
covered by § 97.511(a) of this chapter,
that the State or the permitting authority
submit such allocations or the results of
such auctions for such control period
(except allocations or results of auctions
to such units of TR NOX Ozone Season
allowances remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator no later
than the following dates:
ebenthall on DSK6TPTVN1PROD with RULES2
Year of the control
period for which TR
NOX Ozone Season
allowances are allocated or auctioned
2014 ..........................
2015 ..........................
2016 ..........................
2017 ..........................
2018 ..........................
2019 ..........................
2020 and any year
thereafter.
VerDate Mar<15>2010
Deadline for submission of allocations or
auction results to
administrator
June 1, 2013.
June 1, 2013.
June 1, 2014.
June 1, 2014.
June 1, 2015.
June 1, 2015.
June 1 of the fourth
year before the
year of the control
period.
19:20 Aug 05, 2011
Jkt 223001
(C) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR NOX Ozone Season
allowances for any control period to any
TR NOX Ozone Season units covered by
§§ 97.511(b)(1) and 97.512(a) of this
chapter, that the State or the permitting
authority submit such allocations or the
results of such auctions (except
allocations or results of auctions to such
units of TR NOX Ozone Season
allowances remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator by July 1
of the year of such control period.
(D) Does not provide for any change,
after the submission deadlines in
paragraphs (b)(5)(ii)(B) and (C) of this
section, in the allocations submitted to
the Administrator by such deadlines
and does not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
BBBBB of part 97 of this chapter;
(iii) May adopt in addition to the
definitions in § 97.502 of this chapter,
one or more definitions that shall apply
only to terms as used in the TR NOX
Ozone Season allowance allocation or
auction provisions adopted under
paragraph (b)(5)(ii) of this section;
(iv) May substitute the name of the
State for the term ‘‘State’’ as used in
subpart BBBBB of part 97 of this
chapter, to the extent the Administrator
determines that such substitutions do
not make substantive changes in the
provisions in §§ 97.502 through 97.535
of this chapter; and
(v) Must not include any of the
references to, or requirements imposed
on, any unit in Indian country within
the borders of the State in the provisions
in §§ 97.502 through 97.535 of this
chapter and must not include the
provisions in §§ 97.511(b)(2) and
97.512(b), all of which provisions will
continue to apply under the portion of
the TR Federal Implementation Plan
that is not replaced by the SIP revision;
(vi) Provided that, if and when any
covered unit is located in Indian
country within the borders of the State,
the Administrator may modify his or her
approval of the SIP revision to exclude
the provisions in §§ 97.502 (definitions
of ‘‘common designated representative’’,
‘‘common designated representative’s
assurance level’’, and ‘‘common
designated representative’s share’’),
97.506(c)(2), 97.525, and the portions of
other provisions referencing these
sections and may modify the portion of
the TR Federal Implementation Plan
that is not replaced by the SIP revision
to include these provisions;
(vii) Provided that the State must
submit a complete SIP revision meeting
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48357
the requirements of paragraph (b)(5)(i)
through (v) of this section by December
1 of the year before the year of the
deadlines for submission of allocations
or auction results under paragraphs
(5)(ii)(B) and (C) of this section
applicable to the first control period for
which the State wants to replace the
applicability provisions, make
allocations, or hold an auction under
paragraphs (b)(5)(ii) and (iii) of this
section.
(6) Following promulgation of an
approval by the Administrator of a
State’s SIP revision as correcting in
whole or in part, as appropriate, the
SIP’s deficiency that is the basis for the
TR Federal Implementation Plan set
forth in paragraphs (b)(1) through (5) of
this section, the provisions of paragraph
(b)(2) of this section will no longer
apply to sources in the State, unless the
Administrator’s approval of the SIP
revision is partial or conditional, and
will continue to apply to sources in any
Indian country within the borders of the
State.
(7) Notwithstanding the provisions of
paragraph (b)(6) of this section, if, at the
time of such approval of the State’s SIP
revision, the Administrator has already
started recording any allocations of TR
NOX Ozone Season allowances under
subpart BBBBB of part 97 of this chapter
to units in a State for a control period
in any year, the provisions of subpart
BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
§ 52.39 What are the requirements of the
Federal Implementation Plans (FIPs) for the
Transport Rule (TR) relating to emissions of
sulfur dioxide?
(a) The TR SO2 Group 1 Trading
Program provisions and the TR SO2
Group 2 Trading Program provisions set
forth respectively in subparts CCCCC
and DDDDD of part 97 of this chapter
constitute the TR Federal
Implementation Plan provisions that
relate to emissions of sulfur dioxide
(SO2).
(b) The provisions of subpart CCCCC
of part 97 of this chapter apply to
sources in each of the following States
and Indian country located within the
borders of such States: Illinois, Indiana,
Iowa, Kentucky, Maryland, Michigan,
Missouri, New Jersey, New York, North
Carolina, Ohio, Pennsylvania,
Tennessee, Virginia, West Virginia, and
Wisconsin.
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(c) The provisions of subpart DDDDD
of part 97 of this chapter apply to
sources in each of the following States
and Indian country located within the
borders of such States: Alabama,
Georgia, Kansas, Minnesota, Nebraska,
South Carolina, and Texas.
(d) Notwithstanding the provisions of
paragraph (a) of this section, a State
listed in paragraph (b) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, as TR SO2 Group 1 allowance
allocation provisions replacing the
provisions in § 97.611(a) of this chapter
with regard to the State and the control
period in 2013, a list of TR SO2 Group
1 units and the amount of TR SO2 Group
1 allowances allocated to each unit on
such list, provided that the list of units
and allocations meets the following
requirements:
(1) All of the units on the list must be
units that are in the State and
commenced commercial operation
before January 1, 2010;
(2) The total amount of TR SO2 Group
1 allowance allocations on the list must
not exceed the amount, under
§ 97.610(a) of this chapter for the State
and the control period in 2013, of TR
SO2 Group 1 trading budget minus the
sum of the new unit set-aside and
Indian country new unit set-aside;
(3) The list must be submitted
electronically in a format specified by
the Administrator; and
(4) The SIP revision must not provide
for any change in the units and
allocations on the list after approval of
the SIP revision by the Administrator
and must not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
CCCCC of part 97 of this chapter;
(5) Provided that:
(i) By October 17, 2011, the State must
notify the Administrator electronically
in a format specified by the
Administrator of the State’s intent to
submit to the Administrator a complete
SIP revision meeting the requirements
of paragraph (d)(1) through (4) of this
section by April 1, 2012; and
(ii) The State must submit to the
Administrator a complete SIP revision
described in paragraph (d)(5)(i) of this
section by April 1, 2012.
(e) Notwithstanding the provisions of
paragraph (a) of this section, a State
listed in paragraph (b) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, regulations revising subpart
CCCCC of part 97 of this chapter as
follows and not making any other
substantive revisions of that subpart:
(1) The State may adopt, as TR SO2
Group 1 allowance allocation or auction
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provisions replacing the provisions in
§§ 97.611(a) and (b)(1) and 97.612(a) of
this chapter with regard to the control
period in 2014 or any subsequent year,
any methodology under which the State
or the permitting authority allocates or
auctions TR SO2 Group 1 allowances
and may adopt, in addition to the
definitions in § 97.602 of this chapter,
one or more definitions that shall apply
only to terms as used in the adopted TR
SO2 Group 1 allowance allocation or
auction provisions, if such
methodology—
(i) Requires the State or the permitting
authority to allocate and, if applicable,
auction a total amount of TR SO2 Group
1 allowances for any such control
period not exceeding the amount, under
§§ 97.610(a) and 97.621 of this chapter
for the State and such control period, of
the TR SO2 Group 1 trading budget
minus the sum of the Indian country
new unit set-aside and the amount of
any TR SO2 Group 1 allowances already
allocated and recorded by the
Administrator.
(ii) Requires, to the extent the State
adopts provisions for allocations or
auction of TR SO2 Group 1 allowances
for any such control period to any TR
SO2 Group 1 units covered by
§ 97.611(a) of this chapter, that the State
or the permitting authority submit such
allocations or the results of such
auctions for such control period (except
allocations or results of auctions to such
units of TR SO2 Group 1 allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator no later
than the following dates:
Year of the control
period for which TR
SO2 Group 1 allowances are allocated or
auctioned
Deadline for submission of allocations or
auction results to
administrator
2014 ..........................
2015 ..........................
2016 ..........................
2017 ..........................
2018 ..........................
2019 ..........................
2020 and any year
thereafter.
June 1, 2013.
June 1, 2013.
June 1, 2014.
June 1, 2014.
June 1, 2015.
June 1, 2015.
June 1 of the fourth
year before the
year of the control
period.
(iii) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR SO2 Group 1 allowances
for any such control period to any TR
SO2 Group 1 units covered by
§§ 97.611(b)(1) and 97.612(a) of this
chapter, that the State or the permitting
authority submit such allocations or the
results of such auctions (except
allocations or results of auctions to such
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Sfmt 4700
units of TR SO2 Group 1 allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator by July 1
of the year of such control period.
(iv) Does not provide for any change,
after the submission deadlines in
paragraphs (e)(1)(ii) and (iii) of this
section, in the allocations submitted to
the Administrator by such deadlines
and does not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
CCCCC of part 97 of this chapter;
(2) Provided that the State must
submit a complete SIP revision meeting
the requirements of paragraph (e)(1) of
this section by December 1 of the year
before the year of the deadlines for
submission of allocations or auction
results under paragraphs (e)(1)(ii) and
(iii) of this section applicable to the first
control period for which the State wants
to make allocations or hold an auction
under paragraph (e)(1) of this section.
(f) Notwithstanding the provisions of
paragraph (a) of this section, a State
listed in paragraph (b) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, as correcting in whole or in
part, as appropriate, the deficiency in
the SIP that is the basis for the TR
Federal Implementation Plan set forth in
paragraphs (a), (b), (d), and (e) of this
section, regulations that are
substantively identical to the provisions
of the TR SO2 Group 1 Trading Program
set forth in §§ 97.602 through 97.635 of
this chapter, except that the SIP
revision:
(1) May adopt, as TR SO2 Group 1
allowance allocation or auction
provisions replacing the provisions in
§§ 97.611(a) and (b)(1) and 97.612(a) of
this chapter with regard to the control
period in 2014 and any subsequent year,
any methodology under which the State
or the permitting authority allocates or
auctions TR SO2 Group 1 allowances
and that—
(i) Requires the State or the permitting
authority to allocate and, if applicable,
auction a total amount of TR SO2 Group
1 allowances for such control period not
exceeding the amount, under
§§ 97.610(a) and 97.621 of this chapter
for the State and such control period, of
the TR SO2 Group 1 trading budget
minus the sum of the Indian country
new unit set-aside and the amount of
any TR SO2 Group 1 allowances already
allocated and recorded by the
Administrator.
(ii) Requires, to the extent the State
adopts provisions for allocations or
auction of TR SO2 Group 1 allowances
for any such control period to any TR
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SO2 Group 1 units covered by
§ 97.611(a) of this chapter, that the State
or the permitting authority submit such
allocations or the results of such
auctions for such control period (except
allocations or results of auctions to such
units of TR SO2 Group 1 allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator no later
than the following dates:
Deadline for submission of allocations or
auction results to
administrator
2014 ..........................
2015 ..........................
2016 ..........................
2017 ..........................
2018 ..........................
2019 ..........................
2020 and any year
thereafter.
ebenthall on DSK6TPTVN1PROD with RULES2
Year of the control
period for which TR
SO2 Group 1 allowances are allocated or
auctioned
June 1, 2013.
June 1, 2013.
June 1, 2014.
June 1, 2014.
June 1, 2015.
June 1, 2015.
June 1 of the fourth
year before the
year of the control
period.
(iii) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR SO2 Group 1 allowances
for any such control period to any TR
SO2 Group 1 units covered by
§§ 97.611(b)(1) and 97.612(a) of this
chapter, that the State or the permitting
authority submit such allocations or the
results of such auctions (except
allocations or results of auctions to such
units of TR SO2 Group 1 allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator by July 1
of the year of such control period.
(iv) Does not provide for any change,
after the submission deadlines in
paragraphs (f)(2)(ii) and (iii) of this
section, in the allocations submitted to
the Administrator by such deadlines
and does not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
CCCCC of part 97 of this chapter;
(2) May adopt, in addition to the
definitions in § 97.602 of this chapter,
one or more definitions that shall apply
only to terms as used in the TR SO2
Group 1 allowance allocation or auction
provisions adopted under paragraph
(f)(1) of this section;
(3) May substitute the name of the
State for the term ‘‘State’’ as used in
subpart CCCCC of part 97 of this
chapter, to the extent the Administrator
determines that such substitutions do
not make substantive changes in the
provisions in §§ 97.602 through 97.635
of this chapter; and
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Jkt 223001
(4) Must not include any of the
references to, or requirements imposed
on, any unit in Indian country within
the borders of the State in the provisions
in §§ 97.602 through 97.635 of this
chapter and must not include the
provisions in §§ 97.611(b)(2) and
97.612(b), all of which provisions will
continue to apply under the portion of
the TR Federal Implementation Plan
that is not replaced by the SIP revision;
(5) Provided that, if and when any
covered unit is located in Indian
country within the borders of the State,
the Administrator may modify his or her
approval of the SIP revision to exclude
the provisions in §§ 97.602 (definitions
of ‘‘common designated representative’’,
‘‘common designated representative’s
assurance level’’, and ‘‘common
designated representative’s share’’),
97.606(c)(2), 97.625, and the portions of
other provisions referencing these
sections and may modify the portion of
the TR Federal Implementation Plan
that is not replaced by the SIP revision
to include these provisions;
(6) Provided that the State must
submit a complete SIP revision meeting
the requirements of paragraphs (f)(1)
through (4) of this section by December
1 of the year before the year of the
deadlines for submission of allocations
or auction results under paragraphs
(f)(1)(ii) and (iii) of this section
applicable to the first control period for
which the State wants to make
allocations or hold an auction under
paragraph (f)(1)(ii) and (iii) of this
section.
(g) Notwithstanding the provisions of
paragraph (a) of this section, a State
listed in paragraph (c) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, as TR SO2 Group 2 allowance
allocation provisions replacing the
provisions in § 97.711(a) of this chapter
with regard to the control period in
2013, a list of TR SO2 Group 2 units and
the amount of TR SO2 Group 2
allowances allocated to each unit on
such list, provided that the list of units
and allocations meets the following
requirements:
(1) All of the units on the list must be
units that are in the State and
commenced commercial operation
before January 1, 2010;
(2) The total amount of TR SO2 Group
2 allowance allocations on the list must
not exceed the amount, under
§ 97.710(a) of this chapter for the State
and the control period in 2013, of TR
SO2 Group 2 trading budget minus the
sum of the new unit set-aside and
Indian country new unit set-aside;
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48359
(3) The list must be submitted
electronically in a format specified by
the Administrator; and
(4) The SIP revision must not provide
for any change in the units and
allocations on the list after approval of
the SIP revision by the Administrator
and must not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
DDDDD of part 97 of this chapter;
(5) Provided that:
(i) By October 17, 2011, the State must
notify the Administrator electronically
in a format specified by the
Administrator of the State’s intent to
submit to the Administrator a complete
SIP revision meeting the requirements
of paragraph (g)(1) through (4) of this
section by April 1, 2012; and
(ii) The State must submit to the
Administrator a complete SIP revision
described in paragraph (g)(5)(i) of this
section by April 1, 2012.
(h) Notwithstanding the provisions of
paragraph (a) of this section, a State
listed in paragraph (c) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, regulations revising subpart
DDDDD of part 97 of this chapter as
follows and not making any other
substantive revisions of that subpart:
(1) The State may adopt, as TR SO2
Group 2 allowance allocation or auction
provisions replacing the provisions in
§§ 97.711(a) and (b)(1) and 97.712(a) of
this chapter with regard to the control
period in 2014 and any subsequent year,
any methodology under which the State
or the permitting authority allocates or
auctions TR SO2 Group 2 allowances
and may adopt, in addition to the
definitions in § 97.702 of this chapter,
one or more definitions that shall apply
only to terms as used in the adopted TR
SO2 Group 2 allowance allocation or
auction provisions, if such
methodology—
(i) Requires the State or the permitting
authority to allocate and, if applicable,
auction a total amount of TR SO2 Group
2 allowances for any such control
period not exceeding the amount, under
§§ 97.710(a) and 97.721 of this chapter
for the State and such control period, of
the TR SO2 Group 2 trading budget
minus the sum of the Indian country
new unit set-aside and the amount of
any TR SO2 Group 2 allowances already
allocated and recorded by the
Administrator.
(ii) Requires, to the extent the State
adopts provisions for allocations or
auction of TR SO2 Group 2 allowances
for any such control period to any TR
SO2 Group 2 units covered by
§ 97.711(a) of this chapter, that the State
or the permitting authority submit such
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allocations or the results of such
auctions for such control period (except
allocations or results of auctions to such
units of TR SO2 Group 2 allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator no later
than the following dates:
Deadline for submission of allocations or
auction results to
administrator
2014 ..........................
2015 ..........................
2016 ..........................
2017 ..........................
2018 ..........................
2019 ..........................
2020 and any year
thereafter.
ebenthall on DSK6TPTVN1PROD with RULES2
Year of the control
period for which TR
SO2 Group 2 allowances are allocated or
auctioned
June 1, 2013.
June 1, 2013.
June 1, 2014.
June 1, 2014.
June 1, 2015.
June 1, 2015.
June 1 of the fourth
year before the
year of the control
period.
(iii) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR SO2 Group 2 allowances
for any such control period to any TR
SO2 Group 2 units covered by
§§ 97.711(b)(1) and 97.712(a) of this
chapter, that the State or the permitting
authority submit such allocations or the
results of such auctions (except
allocations or results of auctions to such
units of TR SO2 Group 2 allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator by July 1
of the year of such control period.
(iv) Does not provide for any change,
after the submission deadlines in
paragraphs (h)(1)(ii) and (iii) of this
section, in the allocations submitted to
the Administrator by such deadlines
and does not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
DDDDD of part 97 of this chapter;
(2) Provided that the State must
submit a complete SIP revision meeting
the requirements of paragraph (h)(1) of
this section by December 1 of the year
before the year of the deadlines for
submission of allocations or auction
results under paragraphs (h)(1)(ii) and
(iii) of this section applicable to the first
control period for which the State wants
to make allocations or hold an auction
under paragraph (h)(1)(ii) and (iii) of
this section.
(i) Notwithstanding the provisions of
paragraph (a) of this section, a State
listed in paragraph (c) of this section
may adopt and include in a SIP
revision, and the Administrator will
approve, as correcting in whole or in
part, as appropriate, the deficiency in
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Jkt 223001
the SIP that is the basis for the TR
Federal Implementation Plan set forth in
paragraphs (a), (c), (g), and (h) of this
section, regulations that are
substantively identical to the provisions
of the TR SO2 Group 2 Trading Program
set forth in §§ 97.702 through 97.735 of
this chapter, except that the SIP
revision:
(1) May adopt, as TR SO2 Group 2
allowance allocation or auction
provisions replacing the provisions in
§§ 97.711(a) and (b)(1) and 97.712(a) of
this chapter with regard to the control
period in 2014 and any subsequent year,
any methodology under which the State
or the permitting authority allocates or
auctions TR SO2 Group 2 allowances
and that—
(i) Requires the State or the permitting
authority to allocate and, if applicable,
auction a total amount of TR SO2 Group
2 allowances for any such control
period not exceeding the amount, under
§§ 97.710(a) and 97.721 of this chapter
for the State and such control period, of
the TR SO2 Group 2 trading budget
minus the sum of the Indian country
new unit set-aside and the amount of
any TR SO2 Group 2 allowances already
allocated and recorded by the
Administrator.
(ii) Requires, to the extent the State
adopts provisions for allocations or
auction of TR SO2 Group 2 allowances
for any such control period to any TR
SO2 Group 2 units covered by
§ 97.711(a) of this chapter, that the State
or the permitting authority submit such
allocations or the results of such
auctions for such control period (except
allocations or results of auctions to such
units of TR SO2 Group 1 allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator no later
than the following dates:
Year of the control
period for which TR
SO2 Group 2 allowances are allocated or
auctioned
Deadline for submission of allocations or
auction results to
administrator
2014 ..........................
2015 ..........................
2016 ..........................
2017 ..........................
2018 ..........................
2019 ..........................
2020 and any year
thereafter.
June 1, 2013.
June 1, 2013.
June 1, 2014.
June 1, 2014.
June 1, 2015.
June 1, 2015.
June 1 of the fourth
year before the
year of the control
period.
(iii) Requires, to the extent the State
adopts provisions for allocations or
auctions of TR SO2 Group 2 allowances
for any such control period to any TR
SO2 Group 2 units covered by
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Fmt 4701
Sfmt 4700
§§ 97.711(b)(1) and 97.712(a) of this
chapter, that the State or the permitting
authority submit such allocations or the
results of such auctions (except
allocations or results of auctions to such
units of TR SO2 Group 2 allowances
remaining in a set-aside after
completion of the allocations or
auctions for which the set-aside was
created) to the Administrator by July 1
of the year of such control period.
(iv) Does not provide for any change,
after the submission deadlines in
paragraphs (i)(1)(ii) and (iii) of this
section, in the allocations submitted to
the Administrator by such deadlines
and does not provide for any change in
any allocation determined and recorded
by the Administrator under subpart
DDDDD of part 97 of this chapter;
(2) May adopt, in addition to the
definitions in § 97.702 of this chapter,
one or more definitions that shall apply
only to terms as used in the TR SO2
Group 2 allowance allocation or auction
provisions adopted under paragraph
(i)(1) of this section;
(3) May substitute the name of the
State for the term ‘‘State’’ as used in
subpart DDDDD of part 97 of this
chapter, to the extent the Administrator
determines that such substitutions do
not make substantive changes in the
provisions in §§ 97.702 through 97.735
of this chapter; and
(4) Must not include any of the
references to, or requirements imposed
on, any unit in Indian country within
the borders of the State in the provisions
in §§ 97.702 through 97.735 of this
chapter and must not include the
provisions in §§ 97.711(b)(2) and
97.712(b), all of which provisions will
continue to apply under the portion of
the TR Federal Implementation Plan
that is not replaced by the SIP revision;
(5) Provided that, if and when any
covered unit is located in Indian
country within the borders of the State,
the Administrator may modify his or her
approval of the SIP revision to exclude
the provisions in §§ 97.702 (definitions
of ‘‘common designated representative’’,
‘‘common designated representative’s
assurance level’’, and ‘‘common
designated representative’s share’’),
97.706(c)(2), 97.725, and the portions of
other provisions referencing these
sections and may modify the portion of
the TR Federal Implementation Plan
that is not replaced by the SIP revision
to include these provisions;
(6) Provided that the State must
submit a complete SIP revision meeting
the requirements of paragraphs (i)(1)
through (4) of this section by December
1 of the year before the year of the
deadlines for submission of allocations
or auction results under paragraphs
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(i)(1)(ii) and (iii) of this section
applicable to the first control period for
which the State wants to make
allocations or hold an auction under
paragraphs (i)(1)(ii) and (iii) of this
section.
(j) Following promulgation of an
approval by the Administrator of a
State’s SIP revision as correcting in
whole or in part, as appropriate, the
SIP’s deficiency that is the basis for the
TR Federal Implementation Plan, the
provisions of paragraph (b) and (c) of
this section, as applicable, will no
longer apply to sources in the State,
unless the Administrator’s approval of
the SIP revision is partial or conditional,
and will continue to apply to sources in
any Indian country within the borders
of the State.
(k) Notwithstanding the provisions of
paragraph (j) of this section, if, at the
time of such approval of the State’s SIP
revision, the Administrator has already
started recording any allocations of TR
SO2 Group 1 allowances under subpart
CCCCC of part 97 of this chapter, or
allocations of TR SO2 Group 2
allowances under subpart DDDDD of
part 97 of this chapter, to units in a
State for a control period in any year,
the provisions of subpart CCCCC of part
97 of this chapter authorizing the
Administrator to complete the
allocation and recordation of TR SO2
Group 1 allowances, or of subpart
DDDDD of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 2 allowances, as
applicable, to units in the State for each
such control period shall continue to
apply, unless provided otherwise by
such approval of the State’s SIP
revision.
Subpart B—Alabama
10. Section 52.54 is added to read as
follows:
■
ebenthall on DSK6TPTVN1PROD with RULES2
§ 52.54 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Alabama and for which requirements
are set forth under the TR NOX Annual
Trading Program in subpart AAAAA of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Alabama’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
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Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Alabama’s SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of Alabama and for which requirements
are set forth under the TR NOX Ozone
Season Trading Program in subpart
BBBBB of part 97 of this chapter must
comply with such requirements. The
obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to Alabama’s
State Implementation Plan (SIP) as
correcting the SIP’s deficiency that is
the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of the Alabama’s
SIP revision described in paragraph
(b)(1) of this section, the Administrator
has already started recording any
allocations of TR NOX Ozone Season
allowances under subpart BBBBB of
part 97 of this chapter to units in the
State for a control period in any year,
the provisions of subpart BBBBB of part
97 of this chapter authorizing the
Administrator to complete the
allocation and recordation of TR NOX
Ozone Season allowances to units in the
State for each such control period shall
continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
■ 11. Section 52.55 is added to read as
follows:
§ 52.55 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Alabama and for which requirements
are set forth under the TR SO2 Group 2
Trading Program in subpart DDDDD of
part 97 of this chapter must comply
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Fmt 4701
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48361
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Alabama’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.39, except to the extent the
Administrator’s approval is partial or
conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Alabama’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 2 allowances under
subpart DDDDD of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart DDDDD of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 2 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart E—Arkansas
12. Section 52.184 is added to read as
follows:
■
§ 52.184 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a) The owner and operator of each
source and each unit located in the State
of Arkansas and for which requirements
are set forth under the TR NOX Ozone
Season Trading Program in subpart
BBBBB of part 97 of this chapter must
comply with such requirements. The
obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to Arkansas’
State Implementation Plan (SIP) as
correcting the SIP’s deficiency that is
the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Arkansas’ SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
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units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
Subpart I—Delaware
13. Section 52.440 is amended by
adding a new paragraph (c) to read as
follows:
■
§ 52.440 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
ebenthall on DSK6TPTVN1PROD with RULES2
*
*
*
*
*
(c) Notwithstanding any provisions of
paragraphs (a) and (b) of this section
and subparts AA through II and AAAA
through IIII of part 97 of this chapter to
the contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions in paragraphs (a)
and (b) of this section relating to NOX
annual or ozone season emissions shall
not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AA through II
and AAAA through IIII of part 97 of this
chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any
year thereafter;
(3) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Allowance Tracking System
accounts all CAIR NOX allowances
allocated for a control period in 2012
and any subsequent year, and,
thereafter, no holding or surrender of
CAIR NOX allowances will be required
with regard to emissions or excess
emissions for such control periods; and
(4) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Ozone Season Allowance
Tracking System accounts all CAIR NOX
Ozone Season allowances allocated for
a control period in 2012 and any
subsequent year, and, thereafter, no
holding or surrender of CAIR NOX
Ozone Season allowances will be
required with regard to emissions or
excess emissions for such control
periods.
■ 14. Section 52.441 is amended by
designating the existing text as
paragraph (a) and adding a new
paragraph (b) to read as follows:
§ 52.441 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
*
*
*
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*
*
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(b) Notwithstanding any provisions of
paragraph (a) of this section and
subparts AAA through III of part 97 of
this chapter and any State’s SIP to the
contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions of paragraph (a) of
this section relating to SO2 emissions
shall not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AAA through
III of part 97 of this chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR SO2
allowances allocated for 2012 or any
year thereafter.
Subpart J—District of Columbia
15. Section 52.484 is amended by
adding a new paragraph (c) to read as
follows:
■
§ 52.484 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
*
*
*
*
*
(c) Notwithstanding any provisions of
paragraphs (a) and (b) of this section
and subparts AA through II and AAAA
through IIII of part 97 of this chapter to
the contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions in paragraphs (a)
and (b) of this section relating to NOX
annual or ozone season emissions shall
not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AA through II
and AAAA through IIII of part 97 of this
chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any
year thereafter;
(3) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Allowance Tracking System
accounts all CAIR NOX allowances
allocated for a control period in 2012
and any subsequent year, and,
thereafter, no holding or surrender of
CAIR NOX allowances will be required
with regard to emissions or excess
emissions for such control periods; and
(4) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Ozone Season Allowance
Tracking System accounts all CAIR NOX
Ozone Season allowances allocated for
a control period in 2012 and any
subsequent year, and, thereafter, no
holding or surrender of CAIR NOX
Ozone Season allowances will be
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Fmt 4701
Sfmt 4700
required with regard to emissions or
excess emissions for such control
periods.
■ 16. Section 52.485 is amended by
designating the existing text as
paragraph (a) and adding a new
paragraph (b) to read as follows:
§ 52.485 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
*
*
*
*
*
(b) Notwithstanding any provisions of
paragraph (a) of this section and
subparts AAA through III of part 97 of
this chapter and any State’s SIP to the
contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions of paragraph (a) of
this section relating to SO2 emissions
shall not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AAA through
III of part 97 of this chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR SO2
allowances allocated for 2012 or any
year thereafter.
Subpart K—Florida
17. Section 52.540 is added to read as
follows:
■
§ 52.540 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a) The owner and operator of each
source and each unit located in the State
of Florida and Indian country within the
borders of the State and for which
requirements are set forth under the TR
NOX Ozone Season Trading Program in
subpart BBBBB of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements with regard to sources and
units located in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Florida’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(b), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to Florida’s
SIP.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
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time of the approval of Florida’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
Subpart L—Georgia
18. Section 52.584 is added to read as
follows:
■
ebenthall on DSK6TPTVN1PROD with RULES2
§ 52.584 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Georgia and for which requirements
are set forth under the TR NOX Annual
Trading Program in subpart AAAAA of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Georgia’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Georgia’s SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of Georgia and for which requirements
are set forth under the TR NOX Ozone
Season Trading Program in subpart
BBBBB of part 97 of this chapter must
comply with such requirements. The
obligation to comply with such
requirements will be eliminated by the
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promulgation of an approval by the
Administrator of a revision to Georgia’s
State Implementation Plan (SIP) as
correcting the SIP’s deficiency that is
the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of Georgia’s SIP
revision described in paragraph (b)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
■ 19. Section 52.585 is added to read as
follows:
§ 52.585 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Georgia and for which requirements
are set forth under the TR SO2 Group 2
Trading Program in subpart DDDDD of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Georgia’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.39, except to the extent the
Administrator’s approval is partial or
conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Georgia’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 2 allowances under
subpart DDDDD of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart DDDDD of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 2 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
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48363
Subpart O—Illinois
20. Section 52.745 is added to read as
follows:
■
§ 52.745 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Illinois and for which requirements
are set forth under the TR NOX Annual
Trading Program in subpart AAAAA of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Illinois’ State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Illinois’ SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of Illinois and for which requirements
are set forth under the TR NOX Ozone
Season Trading Program in subpart
BBBBB of part 97 of this chapter must
comply with such requirements. The
obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to Illinois’
State Implementation Plan (SIP) as
correcting the SIP’s deficiency that is
the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of Illinois’ SIP
revision described in paragraph (b)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
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chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
■ 21. Section 52.746 is added to read as
follows:
§ 52.746 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Illinois and for which requirements
are set forth under the TR SO2 Group 1
Trading Program in subpart CCCCC of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Illinois’ State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.39, except to the extent the
Administrator’s approval is partial or
conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Illinois’ SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart P—Indiana
22. Section 52.789 is added to read as
follows:
■
ebenthall on DSK6TPTVN1PROD with RULES2
§ 52.789 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Indiana and for which requirements
are set forth under the TR NOX Annual
Trading Program in subpart AAAAA of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
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be eliminated by the promulgation of an
approval by the Administrator of a
revision to Indiana’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Indiana’s SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of Indiana and for which requirements
are set forth under the TR NOX Ozone
Season Trading Program in subpart
BBBBB of part 97 of this chapter must
comply with such requirements. The
obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to Indiana’s
State Implementation Plan (SIP) as
correcting the SIP’s deficiency that is
the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of Indiana’s SIP
revision described in paragraph (b)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
23. Section 52.790 is added to read as
follows:
■
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§ 52.790 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Indiana and for which requirements
are set forth under the TR SO2 Group 1
Trading Program in subpart CCCCC of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Indiana’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.39 except to the extent the
Administrator’s approval is partial or
conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Indiana’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart Q—Iowa
24. Section 52.840 is added to read as
follows:
■
§ 52.840 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Iowa and Indian country within the
borders of the State and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Iowa’s State Implementation
Plan (SIP) as correcting in part the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional. The obligation to comply
with such requirements with regard to
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sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to Iowa’s
SIP.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Iowa’s SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b) [Reserved]
■ 25. Section 52.841 is added to read as
follows:
ebenthall on DSK6TPTVN1PROD with RULES2
§ 52.841 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Iowa and Indian country within the
borders of the State and for which
requirements are set forth under the TR
SO2 Group 1 Trading Program in
subpart CCCCC of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements with regard to sources and
units in the State will be eliminated by
the promulgation of an approval by the
Administrator of a revision to Iowa’s
State Implementation Plan (SIP) as
correcting in part the SIP’s deficiency
that is the basis for the TR Federal
Implementation Plan under § 52.39,
except to the extent the Administrator’s
approval is partial or conditional. The
obligation to comply with such
requirements with regard to sources and
units located in Indian country within
the borders of the State will not be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Iowa’s SIP.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Iowa’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
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authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart R—Kansas
26. Section 52.882 is added to read as
follows:
■
§ 52.882 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Kansas and Indian country within the
borders of the State and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Kansas’ State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(a), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to Kansas’
SIP.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Kansas’ SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b) [Reserved]
27. Section 52.883 is added to read as
follows:
■
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48365
§ 52.883 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Kansas and Indian country within the
borders of the State and for which
requirements are set forth under the TR
SO2 Group 2 Trading Program in
subpart DDDDD of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements will be
eliminated with regard to sources and
units in the State by the promulgation
of an approval by the Administrator of
a revision to Kansas’ State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.39, except to the extent
the Administrator’s approval is partial
or conditional. The obligation to comply
with such requirements with regard to
sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to Kansas’
SIP.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Kansas’ SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 2 allowances under
subpart DDDDD of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart DDDDD of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 2 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart S—Kentucky
28. Section 52.940 is added to read as
follows:
■
§ 52.940 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Kentucky and for which requirements
are set forth under the TR NOX Annual
Trading Program in subpart AAAAA of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Kentucky’s State
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ebenthall on DSK6TPTVN1PROD with RULES2
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Kentucky’s SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of Kentucky and for which requirements
are set forth under the TR NOX Ozone
Season Trading Program in subpart
BBBBB of part 97 of this chapter must
comply with such requirements. The
obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Kentucky’s State Implementation Plan
(SIP) as correcting the SIP’s deficiency
that is the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of Kentucky’s SIP
revision described in paragraph (b)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
■ 29. Section 52.941 is added to read as
follows:
§ 52.941 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Kentucky and for which requirements
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Jkt 223001
are set forth under the TR SO2 Group 1
Trading Program in subpart CCCCC of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Kentucky’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.39, except to the extent the
Administrator’s approval is partial or
conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Kentucky’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart T—Louisiana
30. Section 52.984 is amended by
adding new paragraphs (c) and (d) to
read as follows:
■
§ 52.984 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
*
*
*
*
*
(c) Notwithstanding any provisions of
paragraphs (a) and (b) of this section
and subparts AA through II and AAAA
through IIII of part 97 of this chapter to
the contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions in paragraphs (a)
and (b) of this section relating to NOX
annual or ozone season emissions shall
not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AA through II
and AAAA through IIII of part 97 of this
chapter;
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any
year thereafter;
(3) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Allowance Tracking System
accounts all CAIR NOX allowances
allocated for a control period in 2012
PO 00000
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Fmt 4701
Sfmt 4700
and any subsequent year, and,
thereafter, no holding or surrender of
CAIR NOX allowances will be required
with regard to emissions or excess
emissions for such control periods; and
(4) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Ozone Season Allowance
Tracking System accounts all CAIR NOX
Ozone Season allowances allocated for
a control period in 2012 and any
subsequent year, and, thereafter, no
holding or surrender of CAIR NOX
Ozone Season allowances will be
required with regard to emissions or
excess emissions for such control
periods.
(d)(1) The owner and operator of each
source and each unit located in the State
of Louisiana and Indian country within
the borders of the State and for which
requirements are set forth under the TR
NOX Ozone Season Trading Program in
subpart BBBBB of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements with regard to sources and
units in the State will be eliminated by
the promulgation of an approval by the
Administrator of a revision to
Louisiana’s State Implementation Plan
(SIP) as correcting in part the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.38(b), except to the extent the
Administrator’s approval is partial or
conditional. The obligation to comply
with such requirements with regard to
sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Louisiana’s SIP.
(2) Notwithstanding the provisions of
paragraph (d)(1) of this section, if, at the
time of the approval of Louisiana’s SIP
revision described in paragraph (d)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
Subpart V—Maryland
31. Section 52.1084 is added to read
as follows:
■
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ebenthall on DSK6TPTVN1PROD with RULES2
§ 52.1084 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Maryland and for which requirements
are set forth under the TR NOX Annual
Trading Program in subpart AAAAA of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Maryland’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Maryland’s SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of Maryland and for which requirements
are set forth under the TR NOX Ozone
Season Trading Program in subpart
BBBBB of part 97 of this chapter must
comply with such requirements. The
obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Maryland’s State Implementation Plan
(SIP) as correcting the SIP’s deficiency
that is the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of Maryland’s SIP
revision described in paragraph (b)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
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Jkt 223001
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
■ 32. Section 52.1085 is added to read
as follows:
§ 52.1085 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Maryland and for which requirements
are set forth under the TR SO2 Group 1
Trading Program in subpart CCCCC of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Maryland’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.39, except to the extent the
Administrator’s approval is partial or
conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Maryland’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart X—Michigan
33. Section 52.1186 is amended by
adding new paragraphs (c) and (d) to
read as follows:
■
§ 52.1186 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
*
*
*
*
*
(c) Notwithstanding any provisions of
paragraphs (a) and (b) of this section
and subparts AA through II and AAAA
through IIII of part 97 of this chapter to
the contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions in paragraphs (a)
and (b) of this section relating to NOX
annual or ozone season emissions shall
not be applicable; and
PO 00000
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48367
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AA through II
and AAAA through IIII of part 97 of this
chapter;
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any
year thereafter;
(3) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Allowance Tracking System
accounts all CAIR NOX allowances
allocated for a control period in 2012
and any subsequent year, and,
thereafter, no holding or surrender of
CAIR NOX allowances will be required
with regard to emissions or excess
emissions for such control periods; and
(4) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Ozone Season Allowance
Tracking System accounts all CAIR NOX
Ozone Season allowances allocated for
a control period in 2012 and any
subsequent year, and, thereafter, no
holding or surrender of CAIR NOX
Ozone Season allowances will be
required with regard to emissions or
excess emissions for such control
periods.
(d)(1) The owner and operator of each
source and each unit located in the State
of Michigan and Indian country within
the borders of the State and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Michigan’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(a), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Michigan’s SIP.
(2) Notwithstanding the provisions of
paragraph (d)(1) of this section, if, at the
time of the approval of Michigan’s SIP
revision described in paragraph (d)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
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subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(e) [Reserved]
■ 34. Section 52.1187 is amended by
designating the existing text as
paragraph (a) and adding new
paragraphs (b) and (c) to read as follows:
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
§ 52.1187 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
Subpart Y—Minnesota
ebenthall on DSK6TPTVN1PROD with RULES2
*
*
*
*
*
(b) Notwithstanding any provisions of
paragraph (a) of this section and
subparts AAA through III of part 97 of
this chapter and any State’s SIP to the
contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions of paragraph (a) of
this section relating to SO2 emissions
shall not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AAA through
III of part 97 of this chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR SO2
allowances allocated for 2012 or any
year thereafter.
(c)(1) The owner and operator of each
source and each unit located in the State
of Michigan and Indian country within
the borders of the State and for which
requirements are set forth under the TR
SO2 Group 1 Trading Program in
subpart CCCCC of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements with regard to sources and
units in the State will be eliminated by
the promulgation of an approval by the
Administrator of a revision to
Michigan’s State Implementation Plan
(SIP) as correcting in part the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.39, except to the extent the
Administrator’s approval is partial or
conditional. The obligation to comply
with such requirements with regard to
sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Michigan’s SIP.
(2) Notwithstanding the provisions of
paragraph (c)(1) of this section, if, at the
time of the approval of Maryland’s SIP
revision described in paragraph (c)(1) of
this section, the Administrator has
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35. Section 52.1240 is amended by
adding paragraph (c) to read as follows:
■
§ 52.1240 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
*
*
*
*
*
(c)(1) The owner and operator of each
source and each unit located in the State
of Minnesota and Indian country within
the borders of the State and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Minnesota’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(a), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Minnesota’s SIP.
(2) Notwithstanding the provisions of
paragraph (c)(1) of this section, if, at the
time of the approval of Minnesota’s SIP
revision described in paragraph (c)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
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36. Section 52.1241 is amended by
adding paragraph (c) to read as follows:
■
§ 52.1241 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
*
*
*
*
*
(c)(1) The owner and operator of each
source and each unit located in the State
of Minnesota and Indian country within
the borders of the State and for which
requirements are set forth under the TR
SO2 Group 2 Trading Program in
subpart DDDDD of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Minnesota’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.39, except to the extent
the Administrator’s approval is partial
or conditional. The obligation to comply
with such requirements with regard to
sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Minnesota’s SIP.
(2) Notwithstanding the provisions of
paragraph (c)(1) of this section, if, at the
time of the approval of Minnesota’s SIP
revision described in paragraph (c)(1) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 2 allowances under
subpart DDDDD of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart DDDDD of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 2 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart Z—Mississippi
37. Section 52.1284 is added to read
as follows:
■
§ 52.1284 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a) The owner and operator of each
source and each unit located in the State
of Mississippi and Indian country
within the borders of the State and for
which requirements are set forth under
the TR NOX Ozone Season Trading
Program in subpart BBBBB of part 97 of
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this chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Mississippi’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(b), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Mississippi’s SIP.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Mississippi’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
Subpart AA—Missouri
38. Section 52.1326 is added to read
as follows:
■
ebenthall on DSK6TPTVN1PROD with RULES2
§ 52.1326 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Missouri and for which requirements
are set forth under the TR NOX Annual
Trading Program in subpart AAAAA of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Missouri’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Missouri’s SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
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already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b) [Reserved]
■ 39. Section 52.1327 is added to read
as follows:
§ 52.1327 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Missouri and for which requirements
are set forth under the TR SO2 Group 1
Trading Program in subpart CCCCC of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Missouri’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.39, except to the extent the
Administrator’s approval is partial or
conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Missouri’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart CC—Nebraska
40. Section 52.1428 is added to read
as follows:
■
§ 52.1428 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a) The owner and operator of each
source and each unit located in the State
of Nebraska and Indian country within
the borders of the State and for which
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48369
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Nebraska’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(a), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Nebraska’s SIP.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Nebraska’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
■ 41. Section 52.1429 is added to read
as follows:
§ 52.1429 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Nebraska and Indian country within
the borders of the State and for which
requirements are set forth under the TR
SO2 Group 2 Trading Program in
subpart DDDDD of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Nebraska’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.39, except to the extent
the Administrator’s approval is partial
or conditional. The obligation to comply
with such requirements with regard to
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sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Nebraska’s SIP.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Nebraska’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 2 allowances under
subpart DDDDD of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart DDDDD of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 2 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart FF—New Jersey
42. Section 52.1584 is amended by
adding new paragraphs (c), (d), and (e)
to read as follows:
■
§ 52.1584 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
ebenthall on DSK6TPTVN1PROD with RULES2
*
*
*
*
*
(c) Notwithstanding any provisions of
paragraphs (a) and (b) of this section
and subparts AA through II and AAAA
through IIII of part 97 of this chapter to
the contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions in paragraphs (a)
and (b) of this section relating to NOX
annual or ozone season emissions shall
not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AA through II
and AAAA through IIII of part 97 of this
chapter;
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any
year thereafter;
(3) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Allowance Tracking System
accounts all CAIR NOX allowances
allocated for a control period in 2012
and any subsequent year, and,
thereafter, no holding or surrender of
CAIR NOX allowances will be required
with regard to emissions or excess
emissions for such control periods; and
(4) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Ozone Season Allowance
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Tracking System accounts all CAIR NOX
Ozone Season allowances allocated for
a control period in 2012 and any
subsequent year, and, thereafter, no
holding or surrender of CAIR NOX
Ozone Season allowances will be
required with regard to emissions or
excess emissions for such control
periods.
(d)(1) The owner and operator of each
source and each unit located in the State
of New Jersey and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to New Jersey’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (d)(1) of this section, if, at the
time of the approval of New Jersey’s SIP
revision described in paragraph (d)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(e)(1) The owner and operator of each
source and each unit located in the State
of New Jersey and for which
requirements are set forth under the TR
NOX Ozone Season Trading Program in
subpart BBBBB of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to New
Jersey’s State Implementation Plan (SIP)
as correcting the SIP’s deficiency that is
the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (e)(1) of this section, if, at the
time of the approval of New Jersey’s SIP
revision described in paragraph (e)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
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Fmt 4701
Sfmt 4700
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
■ 43. Section 52.1585 is amended by
designating the existing text as
paragraph (a) and adding new
paragraphs (b) and (c) to read as follows:
§ 52.1585 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
*
*
*
*
*
(b) Notwithstanding any provisions of
paragraph (a) of this section and
subparts AAA through III of part 97 of
this chapter and any State’s SIP to the
contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions of paragraph (a) of
this section relating to SO2 emissions
shall not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AAA through
III of part 97 of this chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR SO2
allowances allocated for 2012 or any
year thereafter.
(c)(1) The owner and operator of each
source and each unit located in the State
of New Jersey and for which
requirements are set forth under the TR
SO2 Group 1 Trading Program in
subpart CCCCC of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to New
Jersey’s State Implementation Plan (SIP)
as correcting the SIP’s deficiency that is
the basis for the TR Federal
Implementation Plan under § 52.39,
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (c)(1) of this section, if, at the
time of the approval of New Jersey’s SIP
revision described in paragraph (c)(1) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
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of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart HH—New York
44. Section 52.1684 is revised to read
as follows:
■
ebenthall on DSK6TPTVN1PROD with RULES2
§ 52.1684 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of New York and Indian country within
the borders of the State and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to New York’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(a), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to New
York’s SIP.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of New York’s SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of New York and Indian country within
the borders of the State and for which
requirements are set forth under the TR
NOX Ozone Season Trading Program in
subpart BBBBB of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements with regard to sources and
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19:20 Aug 05, 2011
Jkt 223001
units in the State will be eliminated by
the promulgation of an approval by the
Administrator of a revision to New
York’s State Implementation Plan (SIP)
as correcting in part the SIP’s deficiency
that is the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional. The
obligation to comply with such
requirements with regard to sources and
units located in Indian country within
the borders of the State will not be
eliminated by the promulgation of an
approval by the Administrator of a
revision to New York’s SIP.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of New York’s SIP
revision described in paragraph (b)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
■ 45. Section 52.1685 is added to read
as follows:
§ 52.1685 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of New York and Indian country within
the borders of the State and for which
requirements are set forth under the TR
SO2 Group 1 Trading Program in
subpart CCCCC of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements with regard to sources and
units in the State will be eliminated by
the promulgation of an approval by the
Administrator of a revision to New
York’s State Implementation Plan (SIP)
as correcting in part the SIP’s deficiency
that is the basis for the TR Federal
Implementation Plan under § 52.39,
except to the extent the Administrator’s
approval is partial or conditional. The
obligation to comply with such
requirements with regard to sources and
units located in Indian country within
the borders of the State will not be
eliminated by the promulgation of an
approval by the Administrator of a
revision to New York’s SIP.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
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48371
time of the approval of New York’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart II—North Carolina
46. Section 52.1784 is revised to read
as follows:
■
§ 52.1784 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of North Carolina and Indian country
within the borders of the State and for
which requirements are set forth under
the TR NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to North Carolina’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(a), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to North
Carolina’s SIP.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of North Carolina’s
SIP revision described in paragraph
(a)(1) of this section, the Administrator
has already started recording any
allocations of TR NOX Annual
allowances under subpart AAAAA of
part 97 of this chapter to units in the
State for a control period in any year,
the provisions of subpart AAAAA of
part 97 of this chapter authorizing the
Administrator to complete the
allocation and recordation of TR NOX
Annual allowances to units in the State
for each such control period shall
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of North Carolina and Indian country
within the borders of the State and for
which requirements are set forth under
the TR NOX Ozone Season Trading
Program in subpart BBBBB of part 97 of
this chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to North Carolina’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(b), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to North
Carolina’s SIP.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of North Carolina’s
SIP revision described in paragraph
(b)(1) of this section, the Administrator
has already started recording any
allocations of TR NOX Ozone Season
allowances under subpart BBBBB of
part 97 of this chapter to units in the
State for a control period in any year,
the provisions of subpart BBBBB of part
97 of this chapter authorizing the
Administrator to complete the
allocation and recordation of TR NOX
Ozone Season allowances to units in the
State for each such control period shall
continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
■ 47. Section 52.1785 is revised to read
as follows:
ebenthall on DSK6TPTVN1PROD with RULES2
§ 52.1785 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of North Carolina and Indian country
within the borders of the State and for
which requirements are set forth under
the TR SO2 Group 1 Trading Program in
subpart CCCCC of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements with regard to sources and
units in the State will be eliminated by
the promulgation of an approval by the
Administrator of a revision to North
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19:20 Aug 05, 2011
Jkt 223001
Carolina’s State Implementation Plan
(SIP) as correcting in part the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.39, except to the extent the
Administrator’s approval is partial or
conditional. The obligation to comply
with such requirements with regard to
sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to North
Carolina’s SIP.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of North Carolina’s
SIP revision described in paragraph (a)
of this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart KK—Ohio
48. Section 52.1882 is added to read
as follows:
■
§ 52.1882 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Ohio and for which requirements are
set forth under the TR NOX Annual
Trading Program in subpart AAAAA of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Ohio’s State Implementation
Plan (SIP) as correcting the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Ohio’s SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
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Sfmt 4700
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of Ohio and for which requirements are
set forth under the TR NOX Ozone
Season Trading Program in subpart
BBBBB of part 97 of this chapter must
comply with such requirements. The
obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to Ohio’s
State Implementation Plan (SIP) as
correcting the SIP’s deficiency that is
the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of Ohio’s SIP
revision described in paragraph (b)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
■ 49. Section 52.1883 is added to read
as follows:
§ 52.1883 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Ohio and for which requirements are
set forth under the TR SO2 Group 1
Trading Program in subpart CCCCC of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Ohio’s State Implementation
Plan (SIP) as correcting the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.39, except to the extent the
Administrator’s approval is partial or
conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Ohio’s SIP
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revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart NN—Pennsylvania
50. Section 52.2040 is added to read
as follows:
■
ebenthall on DSK6TPTVN1PROD with RULES2
§ 52.2040 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Pennsylvania and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Pennsylvania’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Pennsylvania’s
SIP revision described in paragraph
(a)(1) of this section, the Administrator
has already started recording any
allocations of TR NOX Annual
allowances under subpart AAAAA of
part 97 of this chapter to units in the
State for a control period in any year,
the provisions of subpart AAAAA of
part 97 of this chapter authorizing the
Administrator to complete the
allocation and recordation of TR NOX
Annual allowances to units in the State
for each such control period shall
continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of Pennsylvania and for which
requirements are set forth under the TR
NOX Ozone Season Trading Program in
subpart BBBBB of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
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requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Pennsylvania’s State Implementation
Plan (SIP) as correcting the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.38(b), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of Pennsylvania’s
SIP revision described in paragraph
(b)(1) of this section, the Administrator
has already started recording any
allocations of TR NOX Ozone Season
allowances under subpart BBBBB of
part 97 of this chapter to units in the
State for a control period in any year,
the provisions of subpart BBBBB of part
97 of this chapter authorizing the
Administrator to complete the
allocation and recordation of TR NOX
Ozone Season allowances to units in the
State for each such control period shall
continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
■ 51. Section 52.2041 is added to read
as follows:
§ 52.2041 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Pennsylvania and for which
requirements are set forth under the TR
SO2 Group 1 Trading Program in
subpart CCCCC of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Pennsylvania’s State Implementation
Plan (SIP) as correcting the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.39, except to the extent the
Administrator’s approval is partial or
conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Pennsylvania’s
SIP revision described in paragraph (a)
of this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
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48373
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart PP—South Carolina
52. Section 52.2140 is revised to read
as follows:
■
§ 52.2140 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of South Carolina and Indian country
within the borders of the State and for
which requirements are set forth under
the TR NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to South Carolina’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(a), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to South
Carolina’s SIP.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of South Carolina’s
SIP revision described in paragraph
(a)(1) of this section, the Administrator
has already started recording any
allocations of TR NOX Annual
allowances under subpart AAAAA of
part 97 of this chapter to units in the
State for a control period in any year,
the provisions of subpart AAAAA of
part 97 of this chapter authorizing the
Administrator to complete the
allocation and recordation of TR NOX
Annual allowances to units in the State
for each such control period shall
continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of South Carolina and Indian country
within the borders of the State and for
which requirements are set forth under
the TR NOX Ozone Season Trading
Program in subpart BBBBB of part 97 of
this chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
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eliminated by the promulgation of an
approval by the Administrator of a
revision to South Carolina’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(b), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to South
Carolina’s SIP.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of South Carolina’s
SIP revision described in paragraph
(b)(1) of this section, the Administrator
has already started recording any
allocations of TR NOX Ozone Season
allowances under subpart BBBBB of
part 97 of this chapter to units in the
State for a control period in any year,
the provisions of subpart BBBBB of part
97 of this chapter authorizing the
Administrator to complete the
allocation and recordation of TR NOX
Ozone Season allowances to units in the
State for each such control period shall
continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
■ 53. Section 52.2141 is revised to read
as follows:
ebenthall on DSK6TPTVN1PROD with RULES2
§ 52.2141 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of South Carolina and Indian country
within the borders of the State and for
which requirements are set forth under
the TR SO2 Group 2 Trading Program in
subpart DDDDD of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to South Carolina’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.39, except to the extent
the Administrator’s approval is partial
or conditional. The obligation to comply
with such requirements with regard to
sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to South
Carolina’s SIP.
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Jkt 223001
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of South Carolina’s
SIP revision described in paragraph (a)
of this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart RR—Tennessee
54. Section 52.2240 is amended by
adding new paragraphs (c), (d), and (e)
to read as follows:
■
§ 52.2240 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
*
*
*
*
*
(c) Notwithstanding any provisions of
paragraphs (a) and (b) of this section
and subparts AA through II and AAAA
through IIII of part 97 of this chapter to
the contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions in paragraphs (a)
and (b) of this section relating to NOX
annual or ozone season emissions shall
not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AA through II
and AAAA through IIII of part 97 of this
chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any
year thereafter;
(3) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Allowance Tracking System
accounts all CAIR NOX allowances
allocated for a control period in 2012
and any subsequent year, and,
thereafter, no holding or surrender of
CAIR NOX allowances will be required
with regard to emissions or excess
emissions for such control periods; and
(4) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Ozone Season Allowance
Tracking System accounts all CAIR NOX
Ozone Season allowances allocated for
a control period in 2012 and any
subsequent year, and, thereafter, no
holding or surrender of CAIR NOX
Ozone Season allowances will be
PO 00000
Frm 00168
Fmt 4701
Sfmt 4700
required with regard to emissions or
excess emissions for such control
periods.
(d)(1) The owner and operator of each
source and each unit located in the State
of Tennessee and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Tennessee’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional. The obligation to comply
with such requirements with regard to
sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Tennessee’s SIP.
(2) Notwithstanding the provisions of
paragraph (d)(1) of this section, if, at the
time of the approval of Tennessee’s SIP
revision described in paragraph (d)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(e)(1) The owner and operator of each
source and each unit located in the State
of Tennessee and for which
requirements are set forth under the TR
NOX Ozone Season Trading Program in
subpart BBBBB of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Tennessee’s State Implementation Plan
(SIP) as correcting the SIP’s deficiency
that is the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional. The
obligation to comply with such
requirements with regard to sources and
units located in Indian country within
the borders of the State will not be
eliminated by the promulgation of an
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
approval by the Administrator of a
revision to Tennessee’s SIP.
(2) Notwithstanding the provisions of
paragraph (e)(1) of this section, if, at the
time of the approval of Tennessee’s SIP
revision described in paragraph (e)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
■ 55. Section 52.2241 is amended by
designating the existing text as
paragraph (a) and adding new
paragraphs (b) and (c) to read as follows:
§ 52.2241 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
ebenthall on DSK6TPTVN1PROD with RULES2
*
*
*
*
*
(b) Notwithstanding any provisions of
paragraph (a) of this section and
subparts AAA through III of part 97 of
this chapter and any State’s SIP to the
contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions of paragraph (a) of
this section relating to SO2 emissions
shall not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AAA through
III of part 97 of this chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR SO2
allowances allocated for 2012 or any
year thereafter.
(c)(1) The owner and operator of each
source and each unit located in the State
of Tennessee and for which
requirements are set forth under the TR
SO2 Group 1 Trading Program in
subpart CCCCC of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Tennessee’s State Implementation Plan
(SIP) as correcting the SIP’s deficiency
that is the basis for the TR Federal
Implementation Plan under § 52.39,
except to the extent the Administrator’s
approval is partial or conditional. The
obligation to comply with such
requirements with regard to sources and
units located in Indian country within
the borders of the State will not be
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Jkt 223001
eliminated by the promulgation of an
approval by the Administrator of a
revision to Tennessee’s SIP.
(2) Notwithstanding the provisions of
paragraph (c)(1) of this section, if, at the
time of the approval of Tennessee’s SIP
revision described in paragraph (c)(1) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart SS—Texas
56. Section 52.2283 is amended by
adding new paragraphs (b), (c) and (d)
to read as follows:
■
§ 52.2283 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
*
*
*
*
*
(b) Notwithstanding any provisions of
paragraph (a) of this section and
subparts AA through II of part 97 of this
chapter to the contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions in paragraph (a) of
this section relating to NOX annual
emissions shall not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AA through II
of part 97 of this chapter;
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances allocated for 2012 or any
year thereafter;
(3) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Allowance Tracking System
accounts all CAIR NOX allowances
allocated for a control period in 2012
and any subsequent year, and,
thereafter, no holding or surrender of
CAIR NOX allowances will be required
with regard to emissions or excess
emissions for such control periods.
(c)(1) The owner and operator of each
source and each unit located in the State
of Texas and Indian country within the
borders of the State and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
PO 00000
Frm 00169
Fmt 4701
Sfmt 4700
48375
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Texas’ State Implementation
Plan (SIP) as correcting in part the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional. The obligation to comply
with such requirements with regard to
sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to Texas’
SIP.
(2) Notwithstanding the provisions of
paragraph (c)(1) of this section, if, at the
time of the approval of Texas’ SIP
revision described in paragraph (c)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(d)(1) The owner and operator of each
source and each unit located in the State
of Texas and Indian country within the
borders of the State and for which
requirements are set forth under the TR
NOX Ozone Season Trading Program in
subpart BBBBB of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements with regard to sources and
units in the State will be eliminated by
the promulgation of an approval by the
Administrator of a revision to Texas’
State Implementation Plan (SIP) as
correcting in part the SIP’s deficiency
that is the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional. The
obligation to comply with such
requirements with regard to sources and
units located in Indian country within
the borders of the State will not be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Texas’ SIP.
(2) Notwithstanding the provisions of
paragraph (d)(1) of this section, if, at the
time of the approval of Texas’ SIP
revision described in paragraph (d)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
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chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
■ 57. Section 52.2284 is amended by
designating the existing text as
paragraph (a) and adding new
paragraphs (b) and (c) to read as follows:
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 2 allowances under
subpart DDDDD of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart DDDDD of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 2 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
§ 52.2284 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
Subpart VV—Virginia
ebenthall on DSK6TPTVN1PROD with RULES2
*
*
*
*
*
(b) Notwithstanding any provisions of
paragraph (a) of this section and
subparts AAA through III of part 97 of
this chapter and any State’s SIP to the
contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions of paragraph (a) of
this section relating to SO2 emissions
shall not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AAA through
III of part 97 of this chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR SO2
allowances allocated for 2012 or any
year thereafter.
(c)(1) The owner and operator of each
source and each unit located in the State
of Texas and Indian country within the
borders of the State and for which
requirements are set forth under the TR
SO2 Group 2 Trading Program in
subpart DDDDD of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Texas’ State Implementation
Plan (SIP) as correcting in part the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.39, except to the extent the
Administrator’s approval is partial or
conditional. The obligation to comply
with such requirements with regard to
sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to Texas’
SIP.
(2) Notwithstanding the provisions of
paragraph (c)(1) of this section, if, at the
time of the approval of Texas’ SIP
revision described in paragraph (c)(1) of
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58. Section 52.2440 is added to read
as follows:
■
§ 52.2440 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of Virginia and for which requirements
are set forth under the TR NOX Annual
Trading Program in subpart AAAAA of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Virginia’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of Virginia’s SIP
revision described in paragraph (a)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of Virginia and for which requirements
are set forth under the TR NOX Ozone
Season Trading Program in subpart
BBBBB of part 97 of this chapter must
comply with such requirements. The
obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to Virginia’s
PO 00000
Frm 00170
Fmt 4701
Sfmt 4700
State Implementation Plan (SIP) as
correcting the SIP’s deficiency that is
the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of Virginia’s SIP
revision described in paragraph (b)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Ozone Season allowances
under subpart BBBBB of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart BBBBB of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR NOX Ozone Season allowances to
units in the State for each such control
period shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP revision.
59. Section 52.2241 is added to read
as follows:
■
§ 52.2241 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of Virginia and for which requirements
are set forth under the TR SO2 Group 1
Trading Program in subpart CCCCC of
part 97 of this chapter must comply
with such requirements. The obligation
to comply with such requirements will
be eliminated by the promulgation of an
approval by the Administrator of a
revision to Virginia’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.39, except to the extent the
Administrator’s approval is partial or
conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of Virginia’s SIP
revision described in paragraph (a) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
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Subpart XX—West Virginia
60. Section 52.2540 is added to read
as follows:
■
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§ 52.2540 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
(a)(1) The owner and operator of each
source and each unit located in the State
of West Virginia and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to West Virginia’s State
Implementation Plan (SIP) as correcting
the SIP’s deficiency that is the basis for
the TR Federal Implementation Plan
under § 52.38(a), except to the extent the
Administrator’s approval is partial or
conditional.
(2) Notwithstanding the provisions of
paragraph (a)(1) of this section, if, at the
time of the approval of West Virginia’s
SIP revision described in paragraph
(a)(1) of this section, the Administrator
has already started recording any
allocations of TR NOX Annual
allowances under subpart AAAAA of
part 97 of this chapter to units in the
State for a control period in any year,
the provisions of subpart AAAAA of
part 97 of this chapter authorizing the
Administrator to complete the
allocation and recordation of TR NOX
Annual allowances to units in the State
for each such control period shall
continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
(b)(1) The owner and operator of each
source and each unit located in the State
of West Virginia and for which
requirements are set forth under the TR
NOX Ozone Season Trading Program in
subpart BBBBB of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to West
Virginia’s State Implementation Plan
(SIP) as correcting the SIP’s deficiency
that is the basis for the TR Federal
Implementation Plan under § 52.38(b),
except to the extent the Administrator’s
approval is partial or conditional.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, if, at the
time of the approval of West Virginia’s
SIP revision described in paragraph
(b)(1) of this section, the Administrator
has already started recording any
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allocations of TR NOX Ozone Season
allowances under subpart BBBBB of
part 97 of this chapter to units in the
State for a control period in any year,
the provisions of subpart BBBBB of part
97 of this chapter authorizing the
Administrator to complete the
allocation and recordation of TR NOX
Ozone Season allowances to units in the
State for each such control period shall
continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
■ 61. Section 52.2541 is added to read
as follows:
§ 52.2541 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
(a) The owner and operator of each
source and each unit located in the State
of West Virginia and for which
requirements are set forth under the TR
SO2 Group 1 Trading Program in
subpart CCCCC of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements will be eliminated by the
promulgation of an approval by the
Administrator of a revision to West
Virginia’s State Implementation Plan
(SIP) as correcting the SIP’s deficiency
that is the basis for the TR Federal
Implementation Plan under § 52.39,
except to the extent the Administrator’s
approval is partial or conditional.
(b) Notwithstanding the provisions of
paragraph (a) of this section, if, at the
time of the approval of West Virginia’s
SIP revision described in paragraph (a)
of this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
Subpart YY—Wisconsin
62. Section 52.2587 is amended by
adding new paragraphs (c) and (d) to
read as follows:
■
§ 52.2587 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
*
*
*
*
*
(c) Notwithstanding any provisions of
paragraphs (a) and (b) of this section
and subparts AA through II and AAAA
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48377
through IIII of part 97 of this chapter to
the contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions in paragraphs (a)
and (b) of this section relating to NOX
annual or ozone season emissions shall
not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AA through II
and AAAA through IIII of part 97 of this
chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any
year thereafter;
(3) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Allowance Tracking System
accounts all CAIR NOX allowances
allocated for a control period in 2012
and any subsequent year, and,
thereafter, no holding or surrender of
CAIR NOX allowances will be required
with regard to emissions or excess
emissions for such control periods; and
(4) By November 7, 2011, the
Administrator will remove from the
CAIR NOX Ozone Season Allowance
Tracking System accounts all CAIR NOX
Ozone Season allowances allocated for
a control period in 2012 and any
subsequent year, and, thereafter, no
holding or surrender of CAIR NOX
Ozone Season allowances will be
required with regard to emissions or
excess emissions for such control
periods.
(d)(1) The owner and operator of each
source and each unit located in the State
of Wisconsin and Indian country within
the borders of the State and for which
requirements are set forth under the TR
NOX Annual Trading Program in
subpart AAAAA of part 97 of this
chapter must comply with such
requirements. The obligation to comply
with such requirements with regard to
sources and units in the State will be
eliminated by the promulgation of an
approval by the Administrator of a
revision to Wisconsin’s State
Implementation Plan (SIP) as correcting
in part the SIP’s deficiency that is the
basis for the TR Federal Implementation
Plan under § 52.38(a), except to the
extent the Administrator’s approval is
partial or conditional. The obligation to
comply with such requirements with
regard to sources and units located in
Indian country within the borders of the
State will not be eliminated by the
promulgation of an approval by the
Administrator of a revision to
Wisconsin’s SIP.
(2) Notwithstanding the provisions of
paragraph (d)(1) of this section, if, at the
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time of the approval of Wisconsin’s SIP
revision described in paragraph (d)(1) of
this section, the Administrator has
already started recording any allocations
of TR NOX Annual allowances under
subpart AAAAA of part 97 of this
chapter to units in the State for a control
period in any year, the provisions of
subpart AAAAA of part 97 of this
chapter authorizing the Administrator to
complete the allocation and recordation
of TR NOX Annual allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
■ 63. Section 52.2588 is amended by
designating the existing text as
paragraph (a) and adding new
paragraphs (b) and (c) to read as follows:
Administrator of a revision to
Wisconsin’s SIP.
(2) Notwithstanding the provisions of
paragraph (c)(1) of this section, if, at the
time of the approval of Wisconsin’s SIP
revision described in paragraph (c)(1) of
this section, the Administrator has
already started recording any allocations
of TR SO2 Group 1 allowances under
subpart CCCCC of part 97 of this chapter
to units in the State for a control period
in any year, the provisions of subpart
CCCCC of part 97 of this chapter
authorizing the Administrator to
complete the allocation and recordation
of TR SO2 Group 1 allowances to units
in the State for each such control period
shall continue to apply, unless provided
otherwise by such approval of the
State’s SIP revision.
§ 52.2588 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of sulfur
dioxide?
PART 72—[AMENDED]
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*
*
*
*
*
(b) Notwithstanding any provisions of
paragraph (a) of this section and
subparts AAA through III of part 97 of
this chapter and any State’s SIP to the
contrary:
(1) With regard to any control period
that begins after December 31, 2011,
(i) The provisions of paragraph (a) of
this section relating to SO2 emissions
shall not be applicable; and
(ii) The Administrator will not carry
out any of the functions set forth for the
Administrator in subparts AAA through
III of part 97 of this chapter; and
(2) The Administrator will not deduct
for excess emissions any CAIR SO2
allowances allocated for 2012 or any
year thereafter.
(c)(1) The owner and operator of each
source and each unit located in the State
of Wisconsin and Indian country within
the borders of the State and for which
requirements are set forth under the TR
SO2 Group 1 Trading Program in
subpart CCCCC of part 97 of this chapter
must comply with such requirements.
The obligation to comply with such
requirements with regard to sources and
units in the State will be eliminated by
the promulgation of an approval by the
Administrator of a revision to
Wisconsin’s State Implementation Plan
(SIP) as correcting in part the SIP’s
deficiency that is the basis for the TR
Federal Implementation Plan under
§ 52.39, except to the extent the
Administrator’s approval is partial or
conditional. The obligation to comply
with such requirements with regard to
sources and units located in Indian
country within the borders of the State
will not be eliminated by the
promulgation of an approval by the
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64. The authority citation for part 72
is revised to read as follows:
■
Authority: 42 U.S.C. 7401, 7403, 7410,
7411, 7426, 7601, et seq.
§ 72.2
[Amended]
65. Section 72.2 is amended by
removing the definition of ‘‘Interested
person’’.
■
PART 78—[AMENDED]
66. The authority citation for part 78
continues to read as follows:
■
Authority: 42 U.S.C. 7401, 7403, 7410,
7411, 7426, 7601, et seq.
67. Section 78.1 is amended by adding
paragraphs (b)(13) through (b)(16) to
read as follows:
■
§ 78.1
Purpose and scope.
*
*
*
*
*
(b) * * *
(13) Under subpart AAAAA of part 97
of this chapter,
(i) The decision on allocation of TR
NOX Annual allowances under
§ 97.411(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR
NOX Annual allowances under § 97.423
of this chapter.
(iii) The decision on the deduction of
TR NOX Annual allowances under
§§ 97.424 and 97.425 of this chapter.
(iv) The correction of an error in an
Allowance Management System account
under § 97.427 of this chapter.
(v) The adjustment of information in
a submission and the decision on the
deduction and transfer of TR NOX
Annual allowances based on the
information as adjusted under § 97.428
of this chapter.
(vi) The finalization of control period
emissions data, including retroactive
adjustment based on audit.
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(vii) The approval or disapproval of a
petition under § 97.435 of this chapter.
(14) Under subpart BBBBB of part 97
of this chapter,
(i) The decision on allocation of TR
NOX Ozone Season allowances under
§ 97.511(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR
NOX Ozone Season allowances under
§ 97.523 of this chapter.
(iii) The decision on the deduction of
TR NOX Ozone Season allowances
under §§ 97.524 and 97.525 of this
chapter.
(iv) The correction of an error in an
Allowance Management System account
under § 97.527 of this chapter.
(v) The adjustment of information in
a submission and the decision on the
deduction and transfer of TR NOX
Ozone Season allowances based on the
information as adjusted under § 97.528
of this chapter.
(vi) The finalization of control period
emissions data, including retroactive
adjustment based on audit.
(vii) The approval or disapproval of a
petition under § 97.535 of this chapter.
(15) Under subpart CCCCC of part 97
of this chapter,
(i) The decision on allocation of TR
SO2 Group 1 allowances under
§ 97.611(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR
SO2 Group 1 allowances under § 97.623
of this chapter.
(iii) The decision on the deduction of
TR SO2 Group 1 allowances under
§§ 97.624 and 97.625 of this chapter.
(iv) The correction of an error in an
Allowance Management System account
under § 97.627 of this chapter.
(v) The adjustment of information in
a submission and the decision on the
deduction and transfer of TR SO2 Group
1 allowances based on the information
as adjusted under § 97.628 of this
chapter.
(vi) The finalization of control period
emissions data, including retroactive
adjustment based on audit.
(vii) The approval or disapproval of a
petition under § 97.635 of this chapter.
(16) Under subpart DDDDD of part 97
of this chapter,
(i) The decision on allocation of TR
SO2 Group 2 allowances under
§ 97.711(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR
SO2 Group 1 allowances under § 97.723
of this chapter.
(iii) The decision on the deduction of
TR SO2 Group 1 allowances under
§§ 97.724 and 97.725 of this chapter.
(iv) The correction of an error in an
Allowance Management System account
under § 97.727 of this chapter.
(v) The adjustment of information in
a submission and the decision on the
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deduction and transfer of TR SO2 Group
1 allowances based on the information
as adjusted under § 97.728 of this
chapter.
(vi) The finalization of control period
emissions data, including retroactive
adjustment based on audit.
(vii) The approval or disapproval of a
petition under § 97.735 of this chapter.
*
*
*
*
*
■ 68. Section 78.2 is revised to read as
follows:
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§ 78.2
General.
(a) Definitions. (1) The terms used in
this subpart with regard to a decision of
the Administrator that is appealed
under this section shall have the
meaning as set forth in the regulations
under which the Administrator made
such decision and as set forth in
paragraph (a)(2) of this section.
(2) Interested person means, with
regard to a decision of the
Administrator:
(i) Any person who submitted
comments, or testified at a public
hearing, pursuant to an opportunity for
comment provided by the Administrator
as part of the process of making such
decision;
(ii) Who submitted objections
pursuant to an opportunity for
objections provided by the
Administrator as part of the process of
making such decision; or
(iii) Who submitted, to the
Administrator and in a format
prescribed by the Administrator, his or
her name, service address, telephone
number, and facsimile number and
identified such decision in order to be
placed on a list of persons interested in
such decision;
(iv) Provided that the Administrator
may update the list of interested persons
from time to time by requesting
additional written indication of
continued interest from the persons
listed and may delete from the list the
name of any person failing to respond
as requested.
(b) Availability of information. The
availability to the public of information
provided to, or otherwise obtained by,
the Administrator under this subpart
shall be governed by part 2 of this
chapter.
(c) Computation of time. (1) In
computing any period of time
prescribed or allowed under this part,
except as otherwise provided, the day of
the event from which the period begins
to run shall not be included, and
Saturdays, Sundays, and federal
holidays shall be included. When the
period ends on a Saturday, Sunday, or
federal holiday, the stated period shall
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Jkt 223001
be extended to include the next
business day.
(2) Where a document is served by
first class mail or commercial delivery
service, but not by overnight or sameday delivery, 5 days shall be added to
the time prescribed or allowed under
this part for the filing of a responsive
document or for otherwise responding.
■ 69. Section 78.3 is amended by:
■ a. In paragraphs (a)(1)(iii), (a)(3)(ii),
(a)(4)(ii), (a)(5)(ii), (a)(6)(ii), (a)(7)(ii),
(a)(8)(ii), and (a)(9)(ii), adding, after the
word ‘‘person’’, the words ‘‘with regard
to the decision’’.
■ b. Adding paragraph (a)(10);
■ c. In paragraph (b)(3)(i), removing the
words ‘‘paragraph (a)(1) and (2)’’ and
adding, in their place, the words
‘‘paragraph (a)(1), (2), and (10)’’; and
■ d. Adding paragraph (d)(11) to read as
follows:
§ 78.3 Petition for administrative review
and request or evidentiary hearing.
(a) * * *
(10) The following persons may
petition for administrative review of a
decision of the Administrator that is
made under subparts AAAAA, BBBBB,
CCCCC, and DDDDD of part 97 of this
chapter:
(i) The designated representative for a
unit or source, or the authorized
account representative for any
Allowance Management System
account, covered by the decision; or
(ii) Any interested person with regard
to the decision.
*
*
*
*
*
(d) * * *
(11) Any provision or requirement of
subparts AAAAA, BBBBB, CCCCC, or
DDDDD of part 97 of this chapter,
including the standard requirements
under § 97.406, § 97.506, § 97.606, or
§ 97.706 of this chapter and any
emission monitoring or reporting
requirements.
*
*
*
*
*
■ 70. Section 78.4 is amended by:
■ a. Revising paragraph (a) by:
■ i. Removing the first, second, third,
fourth, fifth, and last sentences;
■ ii. In the sixth and seventh sentences,
removing the words ‘‘interest in’’ and
adding, in their place, the words
‘‘ownership interest with respect to’’;
■ iii. Redesignating the paragraph as
paragraph (a)(1)(iii); and
■ b. Adding paragraphs (a)(1)
introductory text, (a)(1)(i), and (a)(1)(ii);
and
■ c. Revising paragraph (a)(2) to read as
follows:
§ 78.4
Filings.
(a)(1) All original filings made under
this part shall be signed by the person
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48379
making the filing or by an attorney or
authorized representative, in accordance
with the following requirements:
(i) Any filings on behalf of owners
and operators of a affected unit or
affected source, TR NOX Annual unit or
TR NOX Annual source, TR NOX Ozone
Season unit or TR NOX Ozone Season
source, TR SO2 Group 1 unit or TR SO2
Group 1 source, TR SO2 Group 2 unit or
TR SO2 Group 2 source, or a unit for
which a TR opt-in application is
submitted and not withdrawn shall be
signed by the designated representative.
Any filing on behalf of persons with an
ownership interest with respect to
allowances, TR NOX Annual
allowances, TR NOX Ozone Season
allowances, TR SO2 Group 1
allowances, or TR SO2 Group 2
allowances in a general account shall be
signed by the authorized account
representative.
(ii) Any filings on behalf of owners
and operators of a NOX Budget unit or
NOX Budget source shall be signed by
the NOX authorized account
representative. Any filing on behalf of
persons with an ownership interest with
respect to NOX allowances in a general
account shall be signed by the NOX
authorized account representative.
*
*
*
*
*
(2) The name, address, e-mail address
(if any), telephone number, and
facsimile number (if any) of the person
making the filing shall be provided with
the filing.
*
*
*
*
*
§ 78.5
[Amended]
71. Section 78.5 is amended by, in
paragraph (a):
■ a. Removing the words ‘‘public
comment prior to’’ and adding, in their
place, the words ‘‘submission of public
comments or objections prior to’’;
■ b. Removing the words ‘‘public
comment period’’ whenever they appear
and adding, in their place, the words
‘‘period for submission of public
comments or objections’’.
■
§ 78.12
[Amended]
72. Section 78.12 is amended by, in
paragraph (a), removing the words
‘‘public comment’’ and adding, in their
place, the words ‘‘submission of public
comments or objections’’.
■
PART 97—[AMENDED]
73. The authority citation for part 97
continues to read as follows:
Authority: 42 U.S.C. 7401, 7403, 7410,
7426, 7601, and 7651, et seq.
■
74. Part 97 is amended by adding
subpart AAAAA to read as follows:
■
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Subpart AAAAA—TR NOX Annual Trading
Program
97.401 Purpose.
97.402 Definitions.
97.403 Measurements, abbreviations, and
acronyms.
97.404 Applicability.
97.405 Retired unit exemption.
97.406 Standard requirements.
97.407 Computation of time.
97.408 Administrative appeal procedures.
97.409 [Reserved]
97.410 State NOX Annual trading budgets,
new unit set-asides, Indian country new
unit set-asides and variability limits.
97.411 Timing requirements for TR NOX
Annual allowance allocations.
97.412 TR NOX Annual allowance
allocations to new units.
97.413 Authorization of designated
representative and alternate designated
representative.
97.414 Responsibilities of designated
representative and alternate designated
representative.
97.415 Changing designated representative
and alternate designated representative;
changes in owners and operators.
97.416 Certificate of representation.
97.417 Objections concerning designated
representative and alternate designated
representative.
97.418 Delegation by designated
representative and alternate designated
representative.
97.419 [Reserved]
97.420 Establishment of compliance
accounts and general accounts.
97.421 Recordation of TR NOX Annual
allowance allocations.
97.422 Submission of TR NOX Annual
allowance transfers.
97.423 Recordation of TR NOX Annual
allowance transfers.
97.424 Compliance with TR NOX Annual
emissions limitation.
97.425 Compliance with TR NOX Annual
assurance provisions.
97.426 Banking.
97.427 Account error.
97.428 Administrator’s action on
submissions.
97.429 [RESERVED]
97.430 General monitoring, recordkeeping,
and reporting requirements.
97.431 Initial monitoring system
certification and recertification
procedures.
97.432 Monitoring system out-of-control
periods.
97.433 Notifications concerning
monitoring.
97.434 Recordkeeping and reporting.
97.435 Petitions for alternatives to
monitoring, recordkeeping, or reporting
requirements.
Subpart AAAAA—TR NOX Annual
Trading Program
§ 97.401
Purpose.
This subpart sets forth the general,
designated representative, allowance,
and monitoring provisions for the
Transport Rule (TR) NOX Annual
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Trading Program, under section 110 of
the Clean Air Act and § 52.38 of this
chapter, as a means of mitigating
interstate transport of fine particulates
and nitrogen oxides.
§ 97.402
Definitions.
The terms used in this subpart shall
have the meanings set forth in this
section as follows:
Acid Rain Program means a multistate SO2 and NOX air pollution control
and emission reduction program
established by the Administrator under
title IV of the Clean Air Act and parts
72 through 78 of this chapter.
Administrator means the
Administrator of the United States
Environmental Protection Agency or the
Director of the Clean Air Markets
Division (or its successor determined by
the Administrator) of the United States
Environmental Protection Agency, the
Administrator’s duly authorized
representative under this subpart.
Allocate or allocation means, with
regard to TR NOX Annual allowances,
the determination by the Administrator,
State, or permitting authority, in
accordance with this subpart and any
SIP revision submitted by the State and
approved by the Administrator under
§ 52.38(a)(3), (4), or (5) of this chapter,
of the amount of such TR NOX Annual
allowances to be initially credited, at no
cost to the recipient, to:
(1) A TR NOX Annual unit;
(2) A new unit set-aside;
(3) An Indian country new unit setaside; or
(4) An entity not listed in paragraphs
(1) through (3) of this definition;
(5) Provided that, if the
Administrator, State, or permitting
authority initially credits, to a TR NOX
Annual unit qualifying for an initial
credit, a credit in the amount of zero TR
NOX Annual allowances, the TR NOX
Annual unit will be treated as being
allocated an amount (i.e., zero) of TR
NOX Annual allowances.
Allowable NOX emission rate means,
for a unit, the most stringent State or
federal NOX emission rate limit (in lb/
MWhr or, if in lb/mmBtu, converted to
lb/MWhr by multiplying it by the unit’s
heat rate in mmBtu/MWhr) that is
applicable to the unit and covers the
longest averaging period not exceeding
one year.
Allowance Management System
means the system by which the
Administrator records allocations,
deductions, and transfers of TR NOX
Annual allowances under the TR NOX
Annual Trading Program. Such
allowances are allocated, recorded,
held, deducted, or transferred only as
whole allowances.
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Allowance Management System
account means an account in the
Allowance Management System
established by the Administrator for
purposes of recording the allocation,
holding, transfer, or deduction of TR
NOX Annual allowances.
Allowance transfer deadline means,
for a control period in a given year,
midnight of March 1 (if it is a business
day), or midnight of the first business
day thereafter (if March 1 is not a
business day), immediately after such
control period and is the deadline by
which a TR NOX Annual allowance
transfer must be submitted for
recordation in a TR NOX Annual
source’s compliance account in order to
be available for use in complying with
the source’s TR NOX Annual emissions
limitation for such control period in
accordance with §§ 97.406 and 97.424.
Alternate designated representative
means, for a TR NOX Annual source and
each TR NOX Annual unit at the source,
the natural person who is authorized by
the owners and operators of the source
and all such units at the source, in
accordance with this subpart, to act on
behalf of the designated representative
in matters pertaining to the TR NOX
Annual Trading Program. If the TR NOX
Annual source is also subject to the
Acid Rain Program, TR NOX Ozone
Season Trading Program, TR SO2 Group
1 Trading Program, or TR SO2 Group 2
Trading Program, then this natural
person shall be the same natural person
as the alternate designated
representative, as defined in the
respective program.
Assurance account means an
Allowance Management System
account, established by the
Administrator under § 97.425(b)(3) for
certain owners and operators of a group
of one or more TR NOX Annual sources
and units in a given State (and Indian
country within the borders of such
State), in which are held TR NOX
Annual allowances available for use for
a control period in a given year in
complying with the TR NOX Annual
assurance provisions in accordance with
§§ 97.406 and 97.425.
Authorized account representative
means, for a general account, the natural
person who is authorized, in accordance
with this subpart, to transfer and
otherwise dispose of TR NOX Annual
allowances held in the general account
and, for a TR NOX Annual source’s
compliance account, the designated
representative of the source.
Automated data acquisition and
handling system or DAHS means the
component of the continuous emission
monitoring system, or other emissions
monitoring system approved for use
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under this subpart, designed to interpret
and convert individual output signals
from pollutant concentration monitors,
flow monitors, diluent gas monitors,
and other component parts of the
monitoring system to produce a
continuous record of the measured
parameters in the measurement units
required by this subpart.
Biomass means—
(1) Any organic material grown for the
purpose of being converted to energy;
(2) Any organic byproduct of
agriculture that can be converted into
energy; or
(3) Any material that can be converted
into energy and is nonmerchantable for
other purposes, that is segregated from
other material that is nonmerchantable
for other purposes, and that is;
(i) A forest-related organic resource,
including mill residues, precommercial
thinnings, slash, brush, or byproduct
from conversion of trees to
merchantable material; or
(ii) A wood material, including
pallets, crates, dunnage, manufacturing
and construction materials (other than
pressure-treated, chemically-treated, or
painted wood products), and landscape
or right-of-way tree trimmings.
Boiler means an enclosed fossil- or
other-fuel-fired combustion device used
to produce heat and to transfer heat to
recirculating water, steam, or other
medium.
Bottoming-cycle unit means a unit in
which the energy input to the unit is
first used to produce useful thermal
energy, where at least some of the reject
heat from the useful thermal energy
application or process is then used for
electricity production.
Business day means a day that does
not fall on a weekend or a federal
holiday.
Certifying official means a natural
person who is:
(1) For a corporation, a president,
secretary, treasurer, or vice-president of
the corporation in charge of a principal
business function or any other person
who performs similar policy- or
decision-making functions for the
corporation;
(2) For a partnership or sole
proprietorship, a general partner or the
proprietor respectively; or
(3) For a local government entity or
State, federal, or other public agency, a
principal executive officer or ranking
elected official.
Clean Air Act means the Clean Air
Act, 42 U.S.C. 7401, et seq.
Coal means ‘‘coal’’ as defined in
§ 72.2 of this chapter.
Coal-derived fuel means any fuel
(whether in a solid, liquid, or gaseous
state) produced by the mechanical,
thermal, or chemical processing of coal.
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Cogeneration system means an
integrated group, at a source, of
equipment (including a boiler, or
combustion turbine, and a steam turbine
generator) designed to produce useful
thermal energy for industrial,
commercial, heating, or cooling
purposes and electricity through the
sequential use of energy.
Cogeneration unit means a stationary,
fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine that
is a topping-cycle unit or a bottomingcycle unit:
(1) Operating as part of a cogeneration
system; and
(2) Producing on an annual average
basis—
(i) For a topping-cycle unit,
(A) Useful thermal energy not less
than 5 percent of total energy output;
and
(B) Useful power that, when added to
one-half of useful thermal energy
produced, is not less than 42.5 percent
of total energy input, if useful thermal
energy produced is 15 percent or more
of total energy output, or not less than
45 percent of total energy input, if
useful thermal energy produced is less
than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful
power not less than 45 percent of total
energy input;
(3) Provided that the requirements in
paragraph (2) of this definition shall not
apply to a calendar year referenced in
paragraph (2) of this definition during
which the unit did not operate at all;
(4) Provided that the total energy
input under paragraphs (2)(i)(B) and
(2)(ii) of this definition shall equal the
unit’s total energy input from all fuel,
except biomass if the unit is a boiler;
and
(5) Provided that, if, throughout its
operation during the 12-month period or
a calendar year referenced in paragraph
(2) of this definition, a unit is operated
as part of a cogeneration system and the
cogeneration system meets on a systemwide basis the requirement in paragraph
(2)(i)(B) or (2)(ii) of this definition, the
unit shall be deemed to meet such
requirement during that 12-month
period or calendar year.
Combustion turbine means an
enclosed device comprising:
(1) If the device is simple cycle, a
compressor, a combustor, and a turbine
and in which the flue gas resulting from
the combustion of fuel in the combustor
passes through the turbine, rotating the
turbine; and
(2) If the device is combined cycle,
the equipment described in paragraph
(1) of this definition and any associated
duct burner, heat recovery steam
generator, and steam turbine.
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Commence commercial operation
means, with regard to a unit:
(1) To have begun to produce steam,
gas, or other heated medium used to
generate electricity for sale or use,
including test generation, except as
provided in § 97.405.
(i) For a unit that is a TR NOX Annual
unit under § 97.404 on the later of
January 1, 2005 or the date the unit
commences commercial operation as
defined in the introductory text of
paragraph (1) of this definition and that
subsequently undergoes a physical
change or is moved to a new location or
source, such date shall remain the date
of commencement of commercial
operation of the unit, which shall
continue to be treated as the same unit.
(ii) For a unit that is a TR NOX
Annual unit under § 97.404 on the later
of January 1, 2005 or the date the unit
commences commercial operation as
defined in the introductory text of
paragraph (1) of this definition and that
is subsequently replaced by a unit at the
same or a different source, such date
shall remain the replaced unit’s date of
commencement of commercial
operation, and the replacement unit
shall be treated as a separate unit with
a separate date for commencement of
commercial operation as defined in
paragraph (1) or (2) of this definition as
appropriate.
(2) Notwithstanding paragraph (1) of
this definition and except as provided
in § 97.405, for a unit that is not a TR
NOX Annual unit under § 97.404 on the
later of January 1, 2005 or the date the
unit commences commercial operation
as defined in introductory text of
paragraph (1) of this definition, the
unit’s date for commencement of
commercial operation shall be the date
on which the unit becomes a TR NOX
Annual unit under § 97.404.
(i) For a unit with a date for
commencement of commercial
operation as defined in the introductory
text of paragraph (2) of this definition
and that subsequently undergoes a
physical change or is moved to a
different location or source, such date
shall remain the date of commencement
of commercial operation of the unit,
which shall continue to be treated as the
same unit.
(ii) For a unit with a date for
commencement of commercial
operation as defined in the introductory
text of paragraph (2) of this definition
and that is subsequently replaced by a
unit at the same or a different source,
such date shall remain the replaced
unit’s date of commencement of
commercial operation, and the
replacement unit shall be treated as a
separate unit with a separate date for
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commencement of commercial
operation as defined in paragraph (1) or
(2) of this definition as appropriate.
Common designated representative
means, with regard to a control period
in a given year, a designated
representative where, as of April 1
immediately after the allowance transfer
deadline for such control period, the
same natural person is authorized under
§§ 97.413(a) and 97.415(a) as the
designated representative for a group of
one or more TR NOX Annual sources
and units located in a State (and Indian
country within the borders of such
State).
Common designated representative’s
assurance level means, with regard to a
specific common designated
representative and a State (and Indian
country within the borders of such
State) and control period in a given year
for which the State assurance level is
exceeded as described in
§ 97.406(c)(2)(iii), the common
designated representative’s share of the
State NOX Annual trading budget with
the variability limit for the State for
such control period.
Common designated representative’s
share means, with regard to a specific
common designated representative for a
control period in a given year:
(1) With regard to a total amount of
NOX emissions from all TR NOX Annual
units in a State (and Indian country
within the borders of such State) during
such control period, the total tonnage of
NOX emissions during such control
period from a group of one or more TR
NOX Annual units located in such State
(and such Indian country) and having
the common designated representative
for such control period;
(2) With regard to a State NOX Annual
trading budget with the variability limit
for such control period, the amount
(rounded to the nearest allowance)
equal to the sum of the total amount of
TR NOX Annual allowances allocated
for such control period to a group of one
or more TR NOX Annual units located
in the State (and Indian country within
the borders of such State) and having
the common designated representative
for such control period and of the total
amount of TR NOX Annual allowances
purchased by an owner or operator of
such TR NOX Annual units in an
auction for such control period and
submitted by the State or the permitting
authority to the Administrator for
recordation in the compliance accounts
for such TR NOX Annual units in
accordance with the TR NOX Annual
allowance auction provisions in a SIP
revision approved by the Administrator
under § 52.38(a)(4) or (5) of this chapter,
multiplied by the sum of the State NOX
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Annual trading budget under § 97.410(a)
and the State’s variability limit under
§ 97.410(b) for such control period and
divided by such State NOX Annual
trading budget;
(3) Provided that, in the case of a unit
that operates during, but has no amount
of TR NOX Annual allowances allocated
under §§ 97.411 and 97.412 for, such
control period, the unit shall be treated,
solely for purposes of this definition, as
being allocated an amount (rounded to
the nearest allowance) of TR NOX
Annual allowances for such control
period equal to the unit’s allowable NOX
emission rate applicable to such control
period, multiplied by a capacity factor
of 0.85 (if the unit is a boiler combusting
any amount of coal or coal-derived fuel
during such control period), 0.24 (if the
unit is a simple combustion turbine
during such control period), 0.67 (if the
unit is a combined cycle turbine during
such control period), 0.74 (if the unit is
an integrated coal gasification combined
cycle unit during such control period),
or 0.36 (for any other unit), multiplied
by the unit’s maximum hourly load as
reported in accordance with this subpart
and by 8,760 hours/control period, and
divided by 2,000 lb/ton.
Common stack means a single flue
through which emissions from 2 or
more units are exhausted.
Compliance account means an
Allowance Management System
account, established by the
Administrator for a TR NOX Annual
source under this subpart, in which any
TR NOX Annual allowance allocations
to the TR NOX Annual units at the
source are recorded and in which are
held any TR NOX Annual allowances
available for use for a control period in
a given year in complying with the
source’s TR NOX Annual emissions
limitation in accordance with §§ 97.406
and 97.424.
Continuous emission monitoring
system or CEMS means the equipment
required under this subpart to sample,
analyze, measure, and provide, by
means of readings recorded at least once
every 15 minutes and using an
automated data acquisition and
handling system (DAHS), a permanent
record of NOX emissions, stack gas
volumetric flow rate, stack gas moisture
content, and O2 or CO2 concentration (as
applicable), in a manner consistent with
part 75 of this chapter and §§ 97.430
through 97.435. The following systems
are the principal types of continuous
emission monitoring systems:
(1) A flow monitoring system,
consisting of a stack flow rate monitor
and an automated data acquisition and
handling system and providing a
permanent, continuous record of stack
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gas volumetric flow rate, in standard
cubic feet per hour (scfh);
(2) A NOX concentration monitoring
system, consisting of a NOX pollutant
concentration monitor and an
automated data acquisition and
handling system and providing a
permanent, continuous record of NOX
emissions, in parts per million (ppm);
(3) A NOX emission rate (or NOXdiluent) monitoring system, consisting
of a NOX pollutant concentration
monitor, a diluent gas (CO2 or O2)
monitor, and an automated data
acquisition and handling system and
providing a permanent, continuous
record of NOX concentration, in parts
per million (ppm), diluent gas
concentration, in percent CO2 or O2, and
NOX emission rate, in pounds per
million British thermal units
(lb/mmBtu);
(4) A moisture monitoring system, as
defined in § 75.11(b)(2) of this chapter
and providing a permanent, continuous
record of the stack gas moisture content,
in percent H2O;
(5) A CO2 monitoring system,
consisting of a CO2 pollutant
concentration monitor (or an O2 monitor
plus suitable mathematical equations
from which the CO2 concentration is
derived) and an automated data
acquisition and handling system and
providing a permanent, continuous
record of CO2 emissions, in percent CO2;
and
(6) An O2 monitoring system,
consisting of an O2 concentration
monitor and an automated data
acquisition and handling system and
providing a permanent, continuous
record of O2, in percent O2.
Control period means the period
starting January 1 of a calendar year,
except as provided in § 97.406(c)(3), and
ending on December 31 of the same
year, inclusive.
Designated representative means, for
a TR NOX Annual source and each TR
NOX Annual unit at the source, the
natural person who is authorized by the
owners and operators of the source and
all such units at the source, in
accordance with this subpart, to
represent and legally bind each owner
and operator in matters pertaining to the
TR NOX Annual Trading Program. If the
TR NOX Annual source is also subject
to the Acid Rain Program, TR NOX
Ozone Season Trading Program, TR SO2
Group 1 Trading Program, or TR SO2
Group 2 Trading Program, then this
natural person shall be the same natural
person as the designated representative,
as defined in the respective program.
Emissions means air pollutants
exhausted from a unit or source into the
atmosphere, as measured, recorded, and
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reported to the Administrator by the
designated representative, and as
modified by the Administrator:
(1) In accordance with this subpart;
and
(2) With regard to a period before the
unit or source is required to measure,
record, and report such air pollutants in
accordance with this subpart, in
accordance with part 75 of this chapter.
Excess emissions means any ton of
emissions from the TR NOX Annual
units at a TR NOX Annual source during
a control period in a given year that
exceeds the TR NOX Annual emissions
limitation for the source for such control
period.
Fossil fuel means—
(1) Natural gas, petroleum, coal, or
any form of solid, liquid, or gaseous fuel
derived from such material; or
(2) For purposes of applying the
limitation on ‘‘average annual fuel
consumption of fossil fuel’’ in
§§ 97.404(b)(2)(i)(B) and (ii), natural gas,
petroleum, coal, or any form of solid,
liquid, or gaseous fuel derived from
such material for the purpose of creating
useful heat.
Fossil-fuel-fired means, with regard to
a unit, combusting any amount of fossil
fuel in 2005 or any calendar year
thereafter.
General account means an Allowance
Management System account,
established under this subpart, that is
not a compliance account or an
assurance account.
Generator means a device that
produces electricity.
Gross electrical output means, for a
unit, electricity made available for use,
including any such electricity used in
the power production process (which
process includes, but is not limited to,
any on-site processing or treatment of
fuel combusted at the unit and any onsite emission controls).
Heat input means, for a unit for a
specified period of time, the product (in
mmBtu/time) of the gross calorific value
of the fuel (in mmBtu/lb) fed into the
unit multiplied by the fuel feed rate (in
lb of fuel/time), as measured, recorded,
and reported to the Administrator by the
designated representative and as
modified by the Administrator in
accordance with this subpart and
excluding the heat derived from
preheated combustion air, recirculated
flue gases, or exhaust.
Heat input rate means, for a unit, the
amount of heat input (in mmBtu)
divided by unit operating time (in hr)
or, for a unit and a specific fuel, the
amount of heat input attributed to the
fuel (in mmBtu) divided by the unit
operating time (in hr) during which the
unit combusts the fuel.
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Heat rate means, for a unit, the unit’s
maximum design heat input (in Btu/hr),
divided by the product of 1,000,000
Btu/mmBtu and the unit’s maximum
hourly load.
Indian country means ‘‘Indian
country’’ as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power
contractual arrangement means a unit
participation power sales agreement
under which a utility or industrial
customer reserves, or is entitled to
receive, a specified amount or
percentage of nameplate capacity and
associated energy generated by any
specified unit and pays its proportional
amount of such unit’s total costs,
pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less
than 30 years, including contracts that
permit an election for early termination;
or
(3) For a period no less than 25 years
or 70 percent of the economic useful life
of the unit determined as of the time the
unit is built, with option rights to
purchase or release some portion of the
nameplate capacity and associated
energy generated by the unit at the end
of the period.
Maximum design heat input means,
for a unit, the maximum amount of fuel
per hour (in Btu/hr) that the unit is
capable of combusting on a steady state
basis as of the initial installation of the
unit as specified by the manufacturer of
the unit.
Monitoring system means any
monitoring system that meets the
requirements of this subpart, including
a continuous emission monitoring
system, an alternative monitoring
system, or an excepted monitoring
system under part 75 of this chapter.
Nameplate capacity means, starting
from the initial installation of a
generator, the maximum electrical
generating output (in MWe, rounded to
the nearest tenth) that the generator is
capable of producing on a steady state
basis and during continuous operation
(when not restricted by seasonal or
other deratings) as of such installation
as specified by the manufacturer of the
generator or, starting from the
completion of any subsequent physical
change in the generator resulting in an
increase in the maximum electrical
generating output that the generator is
capable of producing on a steady state
basis and during continuous operation
(when not restricted by seasonal or
other deratings), such increased
maximum amount (in MWe, rounded to
the nearest tenth) as of such completion
as specified by the person conducting
the physical change.
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Natural gas means ‘‘natural gas’’ as
defined in § 72.2 of this chapter.
Newly affected TR NOX Annual unit
means a unit that was not a TR NOX
Annual unit when it began operating
but that thereafter becomes a TR NOX
Annual unit.
Operate or operation means, with
regard to a unit, to combust fuel.
Operator means, for a TR NOX Annual
source or a TR NOX Annual unit at a
source respectively, any person who
operates, controls, or supervises a TR
NOX Annual unit at the source or the TR
NOX Annual unit and shall include, but
not be limited to, any holding company,
utility system, or plant manager of such
source or unit.
Owner means, for a TR NOX Annual
source or a TR NOX Annual unit at a
source respectively, any of the following
persons:
(1) Any holder of any portion of the
legal or equitable title in a TR NOX
Annual unit at the source or the TR NOX
Annual unit;
(2) Any holder of a leasehold interest
in a TR NOX Annual unit at the source
or the TR NOX Annual unit, provided
that, unless expressly provided for in a
leasehold agreement, ‘‘owner’’ shall not
include a passive lessor, or a person
who has an equitable interest through
such lessor, whose rental payments are
not based (either directly or indirectly)
on the revenues or income from such TR
NOX Annual unit; and 3) Any purchaser
of power from a TR NOX Annual unit
at the source or the TR NOX Annual unit
under a life-of-the-unit, firm power
contractual arrangement.
Permanently retired means, with
regard to a unit, a unit that is
unavailable for service and that the
unit’s owners and operators do not
expect to return to service in the future.
Permitting authority means
‘‘permitting authority’’ as defined in
§§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity
means, for a unit, 33 percent of the
unit’s maximum design heat input,
divided by 3,413 Btu/kWh, divided by
1,000 kWh/MWh, and multiplied by
8,760 hr/yr.
Receive or receipt of means, when
referring to the Administrator, to come
into possession of a document,
information, or correspondence
(whether sent in hard copy or by
authorized electronic transmission), as
indicated in an official log, or by a
notation made on the document,
information, or correspondence, by the
Administrator in the regular course of
business.
Recordation, record, or recorded
means, with regard to TR NOX Annual
allowances, the moving of TR NOX
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Annual allowances by the
Administrator into, out of, or between
Allowance Management System
accounts, for purposes of allocation,
auction, transfer, or deduction.
Reference method means any direct
test method of sampling and analyzing
for an air pollutant as specified in
§ 75.22 of this chapter.
Replacement, replace, or replaced
means, with regard to a unit, the
demolishing of a unit, or the permanent
retirement and permanent disabling of a
unit, and the construction of another
unit (the replacement unit) to be used
instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from
electricity production in a useful
thermal energy application or process;
or
(2) The use of reject heat from useful
thermal energy application or process in
electricity production.
Serial number means, for a TR NOX
Annual allowance, the unique
identification number assigned to each
TR NOX Annual allowance by the
Administrator.
Solid waste incineration unit means a
stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion
turbine that is a ‘‘solid waste
incineration unit’’ as defined in section
129(g)(1) of the Clean Air Act.
Source means all buildings,
structures, or installations located in
one or more contiguous or adjacent
properties under common control of the
same person or persons. This definition
does not change or otherwise affect the
definition of ‘‘major source’’, ‘‘stationary
source’’, or ‘‘source’’ as set forth and
implemented in a title V operating
permit program or any other program
under the Clean Air Act.
State means one of the States that is
subject to the TR NOX Annual Trading
Program pursuant to § 52.38(a) of this
chapter.
Submit or serve means to send or
transmit a document, information, or
correspondence to the person specified
in accordance with the applicable
regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or
transmission and delivery;
(4) Provided that compliance with any
‘‘submission’’ or ‘‘service’’ deadline
shall be determined by the date of
dispatch, transmission, or mailing and
not the date of receipt.
Topping-cycle unit means a unit in
which the energy input to the unit is
first used to produce useful power,
including electricity, where at least
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some of the reject heat from the
electricity production is then used to
provide useful thermal energy.
Total energy input means, for a unit,
total energy of all forms supplied to the
unit, excluding energy produced by the
unit. Each form of energy supplied shall
be measured by the lower heating value
of that form of energy calculated as
follows:
LHV = HHV ¥ 10.55(W + 9H)
Where:
LHV = lower heating value of the form of
energy in Btu/lb,
HHV = higher heating value of the form of
energy in Btu/lb,
W = weight % of moisture in the form of
energy, and
H = weight % of hydrogen in the form of
energy.
Total energy output means, for a unit,
the sum of useful power and useful
thermal energy produced by the unit.
TR NOX Annual allowance means a
limited authorization issued and
allocated or auctioned by the
Administrator under this subpart, or by
a State or permitting authority under a
SIP revision approved by the
Administrator under § 52.38(a)(3), (4), or
(5) of this chapter, to emit one ton of
NOX during a control period of the
specified calendar year for which the
authorization is allocated or auctioned
or of any calendar year thereafter under
the TR NOX Annual Trading Program.
TR NOX Annual allowance deduction
or deduct TR NOX Annual allowances
means the permanent withdrawal of TR
NOX Annual allowances by the
Administrator from a compliance
account (e.g., in order to account for
compliance with the TR NOX Annual
emissions limitation) or from an
assurance account (e.g., in order to
account for compliance with the
assurance provisions under §§ 97.406
and 97.425).
TR NOX Annual allowances held or
hold TR NO4 Annual allowances means
the TR NOX Annual allowances treated
as included in an Allowance
Management System account as of a
specified point in time because at that
time they:
(1) Have been recorded by the
Administrator in the account or
transferred into the account by a
correctly submitted, but not yet
recorded, TR NOX Annual allowance
transfer in accordance with this subpart;
and
(2) Have not been transferred out of
the account by a correctly submitted,
but not yet recorded, TR NOX Annual
allowance transfer in accordance with
this subpart.
TR NOX Annual emissions limitation
means, for a TR NOX Annual source, the
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tonnage of NOX emissions authorized in
a control period in a given year by the
TR NOX Annual allowances available
for deduction for the source under
§ 97.424(a) for such control period.
TR NOX Annual source means a
source that includes one or more TR
NOX Annual units.
TR NOX Annual Trading Program
means a multi-state NOX air pollution
control and emission reduction program
established in accordance with this
subpart and § 52.38(a) of this chapter
(including such a program that is
revised in a SIP revision approved by
the Administrator under § 52.38(a)(3) or
(4) of this chapter or that is established
in a SIP revision approved by the
Administrator under § 52.38(a)(5) of this
chapter), as a means of mitigating
interstate transport of fine particulates
and NOX.
TR NOX Annual unit means a unit
that is subject to the TR NOX Annual
Trading Program.
TR NOX Ozone Season Trading
Program means a multi-state NOX air
pollution control and emission
reduction program established in
accordance with subpart BBBBB of this
part and § 52.38(b) of this chapter
(including such a program that is
revised in a SIP revision approved by
the Administrator under § 52.38(b)(3) or
(4) of this chapter or that is established
in a SIP revision approved by the
Administrator under § 52.38(b)(5) of this
chapter), as a means of mitigating
interstate transport of ozone and NOX.
TR SO2 Group 1 Trading Program
means a multi-state SO2 air pollution
control and emission reduction program
established in accordance with subpart
CCCCC of this part and § 52.39(a), (b),
(d) through (f), (j), and (k) of this chapter
(including such a program that is
revised in a SIP revision approved by
the Administrator under § 52.39(d) or (e)
of this chapter or that is established in
a SIP revision approved by the
Administrator under § 52.39(f) of this
chapter), as a means of mitigating
interstate transport of fine particulates
and SO2.
TR SO2 Group 2 Trading Program
means a multi-state SO2 air pollution
control and emission reduction program
established in accordance with subpart
DDDDD of this part and 52.39(a), (c),
and (g) through (k) of this chapter
(including such a program that is
revised in a SIP revision approved by
the Administrator under § 52.39(g) or (h)
of this chapter or that is established in
a SIP revision approved by the
Administrator under § 52.39(i) of this
chapter), as a means of mitigating
interstate transport of fine particulates
and SO2.
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Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired
combustion turbine, or other stationary,
fossil-fuel-fired combustion device. A
unit that undergoes a physical change or
is moved to a different location or
source shall continue to be treated as
the same unit. A unit (the replaced unit)
that is replaced by another unit (the
replacement unit) at the same or a
different source shall continue to be
treated as the same unit, and the
replacement unit shall be treated as a
separate unit.
Unit operating day means, with
regard to a unit, a calendar day in which
the unit combusts any fuel.
Unit operating hour or hour of unit
operation means, with regard to a unit,
an hour in which the unit combusts any
fuel.
Useful power means, with regard to a
unit, electricity or mechanical energy
that the unit makes available for use,
excluding any such energy used in the
power production process (which
process includes, but is not limited to,
any on-site processing or treatment of
fuel combusted at the unit and any onsite emission controls).
Useful thermal energy means thermal
energy that is:
(1) Made available to an industrial or
commercial process (not a power
production process), excluding any heat
contained in condensate return or
makeup water;
(2) Used in a heating application (e.g.,
space heating or domestic hot water
heating); or
(3) Used in a space cooling
application (i.e., in an absorption
chiller).
Utility power distribution system
means the portion of an electricity grid
owned or operated by a utility and
dedicated to delivering electricity to
customers.
§ 97.403 Measurements, abbreviations,
and acronyms.
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Measurements, abbreviations, and
acronyms used in this subpart are
defined as follows:
Btu—British thermal unit
CO2—carbon dioxide
H2O—water
hr—hour
kW—kilowatt electrical
kWh—kilowatt hour
lb—pound
mmBtu—million Btu
MWe—megawatt electrical
MWh—megawatt hour
NOX—nitrogen oxides
O2—oxygen
ppm—parts per million
scfh—standard cubic feet per hour
SO2—sulfur dioxide
yr—year
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§ 97.404
Applicability.
(a) Except as provided in paragraph
(b) of this section:
(1) The following units in a State (and
Indian country within the borders of
such State) shall be TR NOX Annual
units, and any source that includes one
or more such units shall be a TR NOX
Annual source, subject to the
requirements of this subpart: any
stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion
turbine serving at any time, on or after
January 1, 2005, a generator with
nameplate capacity of more than 25
MWe producing electricity for sale.
(2) If a stationary boiler or stationary
combustion turbine that, under
paragraph (a)(1) of this section, is not a
TR NOX Annual unit begins to combust
fossil fuel or to serve a generator with
nameplate capacity of more than 25
MWe producing electricity for sale, the
unit shall become a TR NOX Annual
unit as provided in paragraph (a)(1) of
this section on the first date on which
it both combusts fossil fuel and serves
such generator.
(b) Any unit in a State (and Indian
country within the borders of such
State) that otherwise is a TR NOX
Annual unit under paragraph (a) of this
section and that meets the requirements
set forth in paragraph (b)(1)(i) or (2)(i) of
this section shall not be a TR NOX
Annual unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit
throughout the later of 2005 or the
12-month period starting on the date the
unit first produces electricity and
continuing to qualify as a cogeneration
unit throughout each calendar year
ending after the later of 2005 or such
12-month period; and
(B) Not supplying in 2005 or any
calendar year thereafter more than onethird of the unit’s potential electric
output capacity or 219,000 MWh,
whichever is greater, to any utility
power distribution system for sale.
(ii) If, after qualifying under
paragraph (b)(1)(i) of this section as not
being a TR NOX Annual unit, a unit
subsequently no longer meets all the
requirements of paragraph (b)(1)(i) of
this section, the unit shall become a TR
NOX Annual unit starting on the earlier
of January 1 after the first calendar year
during which the unit first no longer
qualifies as a cogeneration unit or
January 1 after the first calendar year
during which the unit no longer meets
the requirements of paragraph
(b)(1)(i)(B) of this section. The unit shall
thereafter continue to be a TR NOX
Annual unit.
(2)(i) Any unit:
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48385
(A) Qualifying as a solid waste
incineration unit throughout the later of
2005 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit
throughout each calendar year ending
after the later of 2005 or such 12-month
period; and
(B) With an average annual fuel
consumption of fossil fuel for the first
3 consecutive calendar years of
operation starting no earlier than 2005
of less than 20 percent (on a Btu basis)
and an average annual fuel consumption
of fossil fuel for any 3 consecutive
calendar years thereafter of less than 20
percent (on a Btu basis).
(ii) If, after qualifying under
paragraph (b)(2)(i) of this section as not
being a TR NOX Annual unit, a unit
subsequently no longer meets all the
requirements of paragraph (b)(1)(i) of
this section, the unit shall become a TR
NOX Annual unit starting on the earlier
of January 1 after the first calendar year
during which the unit first no longer
qualifies as a solid waste incineration
unit or January 1 after the first 3
consecutive calendar years after 2005
for which the unit has an average
annual fuel consumption of fossil fuel of
20 percent or more. The unit shall
thereafter continue to be a TR NOX
Annual unit.
(c) A certifying official of an owner or
operator of any unit or other equipment
may submit a petition (including any
supporting documents) to the
Administrator at any time for a
determination concerning the
applicability, under paragraphs (a) and
(b) of this section or a SIP revision
approved under § 52.38(a)(4) or (5) of
this chapter, of the TR NOX Annual
Trading Program to the unit or other
equipment.
(1) Petition content. The petition shall
be in writing and include the
identification of the unit or other
equipment and the relevant facts about
the unit or other equipment. The
petition and any other documents
provided to the Administrator in
connection with the petition shall
include the following certification
statement, signed by the certifying
official: ‘‘I am authorized to make this
submission on behalf of the owners and
operators of the unit or other equipment
for which the submission is made. I
certify under penalty of law that I have
personally examined, and am familiar
with, the statements and information
submitted in this document and all its
attachments. Based on my inquiry of
those individuals with primary
responsibility for obtaining the
information, I certify that the statements
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and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(2) Response. The Administrator will
issue a written response to the petition
and may request supplemental
information determined by the
Administrator to be relevant to such
petition. The Administrator’s
determination concerning the
applicability, under paragraphs (a) and
(b) of this section, of the TR NOX
Annual Trading Program to the unit or
other equipment shall be binding on any
State or permitting authority unless the
Administrator determines that the
petition or other documents or
information provided in connection
with the petition contained significant,
relevant errors or omissions.
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§ 97.405
Retired unit exemption.
(a)(1) Any TR NOX Annual unit that
is permanently retired shall be exempt
from § 97.406(b) and (c)(1), § 97.424,
and §§ 97.430 through 97.435.
(2) The exemption under paragraph
(a)(1) of this section shall become
effective the day on which the TR NOX
Annual unit is permanently retired.
Within 30 days of the unit’s permanent
retirement, the designated
representative shall submit a statement
to the Administrator. The statement
shall state, in a format prescribed by the
Administrator, that the unit was
permanently retired on a specified date
and will comply with the requirements
of paragraph (b) of this section.
(b) Special provisions. (1) A unit
exempt under paragraph (a) of this
section shall not emit any NOX, starting
on the date that the exemption takes
effect.
(2) For a period of 5 years from the
date the records are created, the owners
and operators of a unit exempt under
paragraph (a) of this section shall retain,
at the source that includes the unit,
records demonstrating that the unit is
permanently retired. The 5-year period
for keeping records may be extended for
cause, at any time before the end of the
period, in writing by the Administrator.
The owners and operators bear the
burden of proof that the unit is
permanently retired.
(3) The owners and operators and, to
the extent applicable, the designated
representative of a unit exempt under
paragraph (a) of this section shall
comply with the requirements of the TR
NOX Annual Trading Program
concerning all periods for which the
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Jkt 223001
exemption is not in effect, even if such
requirements arise, or must be complied
with, after the exemption takes effect.
(4) A unit exempt under paragraph (a)
of this section shall lose its exemption
on the first date on which the unit
resumes operation. Such unit shall be
treated, for purposes of applying
allocation, monitoring, reporting, and
recordkeeping requirements under this
subpart, as a unit that commences
commercial operation on the first date
on which the unit resumes operation.
§ 97.406
Standard requirements.
(a) Designated representative
requirements. The owners and operators
shall comply with the requirement to
have a designated representative, and
may have an alternate designated
representative, in accordance with
§§ 97.413 through 97.418.
(b) Emissions monitoring, reporting,
and recordkeeping requirements.
(1) The owners and operators, and the
designated representative, of each TR
NOX Annual source and each TR NOX
Annual unit at the source shall comply
with the monitoring, reporting, and
recordkeeping requirements of §§ 97.430
through 97.435.
(2) The emissions data determined in
accordance with §§ 97.430 through
97.435 shall be used to calculate
allocations of TR NOX Annual
allowances under §§ 97.411(a)(2) and (b)
and 97.412 and to determine
compliance with the TR NOX Annual
emissions limitation and assurance
provisions under paragraph (c) of this
section, provided that, for each
monitoring location from which mass
emissions are reported, the mass
emissions amount used in calculating
such allocations and determining such
compliance shall be the mass emissions
amount for the monitoring location
determined in accordance with
§§ 97.430 through 97.435 and rounded
to the nearest ton, with any fraction of
a ton less than 0.50 being deemed to be
zero.
(c) NOX emissions requirements. (1)
TR NOX Annual emissions limitation. (i)
As of the allowance transfer deadline for
a control period in a given year, the
owners and operators of each TR NOX
Annual source and each TR NOX
Annual unit at the source shall hold, in
the source’s compliance account, TR
NOX Annual allowances available for
deduction for such control period under
§ 97.424(a) in an amount not less than
the tons of total NOX emissions for such
control period from all TR NOX Annual
units at the source.
(ii) If total NOX emissions during a
control period in a given year from the
TR NOX Annual units at a TR NOX
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Sfmt 4700
Annual source are in excess of the TR
NOX Annual emissions limitation set
forth in paragraph (c)(1)(i) of this
section, then:
(A) The owners and operators of the
source and each TR NOX Annual unit at
the source shall hold the TR NOX
Annual allowances required for
deduction under § 97.424(d); and
(B) The owners and operators of the
source and each TR NOX Annual unit at
the source shall pay any fine, penalty,
or assessment or comply with any other
remedy imposed, for the same
violations, under the Clean Air Act, and
each ton of such excess emissions and
each day of such control period shall
constitute a separate violation of this
subpart and the Clean Air Act.
(2) TR NOX Annual assurance
provisions. (i) If total NOX emissions
during a control period in a given year
from all TR NOX Annual units at TR
NOX Annual sources in a State (and
Indian country within the borders of
such State) exceed the State assurance
level, then the owners and operators of
such sources and units in each group of
one or more sources and units having a
common designated representative for
such control period, where the common
designated representative’s share of
such NOX emissions during such
control period exceeds the common
designated representative’s assurance
level for the State and such control
period, shall hold (in the assurance
account established for the owners and
operators of such group) TR NOX
Annual allowances available for
deduction for such control period under
§ 97.425(a) in an amount equal to two
times the product (rounded to the
nearest whole number), as determined
by the Administrator in accordance with
§ 97.425(b), of multiplying—
(A) The quotient of the amount by
which the common designated
representative’s share of such NOX
emissions exceeds the common
designated representative’s assurance
level divided by the sum of the
amounts, determined for all common
designated representatives for such
sources and units in the State (and
Indian country within the borders of
such State) for such control period, by
which each common designated
representative’s share of such NOX
emissions exceeds the respective
common designated representative’s
assurance level; and
(B) The amount by which total NOX
emissions from all TR NOX Annual
units at TR NOX Annual sources in the
State (and Indian country within the
borders of such State) for such control
period exceed the State assurance level.
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
(ii) The owners and operators shall
hold the TR NOX Annual allowances
required under paragraph (c)(2)(i) of this
section, as of midnight of November 1
(if it is a business day), or midnight of
the first business day thereafter (if
November 1 is not a business day),
immediately after such control period.
(iii) Total NOX emissions from all TR
NOX Annual units at TR NOX Annual
sources in a State (and Indian country
within the borders of such State) during
a control period in a given year exceed
the State assurance level if such total
NOX emissions exceed the sum, for such
control period, of the State NOX Annual
trading budget under § 97.410(a) and the
State’s variability limit under
§ 97.410(b).
(iv) It shall not be a violation of this
subpart or of the Clean Air Act if total
NOX emissions from all TR NOX Annual
units at TR NOX Annual sources in a
State (and Indian country within the
borders of such State) during a control
period exceed the State assurance level
or if a common designated
representative’s share of total NOX
emissions from the TR NOX Annual
units at TR NOX Annual sources in a
State (and Indian country within the
borders of such State) during a control
period exceeds the common designated
representative’s assurance level.
(v) To the extent the owners and
operators fail to hold TR NOX Annual
allowances for a control period in a
given year in accordance with
paragraphs (c)(2)(i) through (iii) of this
section,
(A) The owners and operators shall
pay any fine, penalty, or assessment or
comply with any other remedy imposed
under the Clean Air Act; and
(B) Each TR NOX Annual allowance
that the owners and operators fail to
hold for such control period in
accordance with paragraphs (c)(2)(i)
through (iii) of this section and each day
of such control period shall constitute a
separate violation of this subpart and
the Clean Air Act.
(3) Compliance periods. A TR NOX
Annual unit shall be subject to the
requirements under paragraphs (c)(1)
and (c)(2) of this section for the control
period starting on the later of January 1,
2012 or the deadline for meeting the
unit’s monitor certification
requirements under § 97.430(b) and for
each control period thereafter.
(4) Vintage of allowances held for
compliance. (i) A TR NOX Annual
allowance held for compliance with the
requirements under paragraph (c)(1)(i)
of this section for a control period in a
given year must be a TR NOX Annual
allowance that was allocated for such
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control period or a control period in a
prior year.
(ii) A TR NOX Annual allowance held
for compliance with the requirements
under paragraphs (c)(1)(ii)(A) and (2)(i)
through (iii) of this section for a control
period in a given year must be a TR NOX
Annual allowance that was allocated for
a control period in a prior year or the
control period in the given year or in the
immediately following year.
(5) Allowance Management System
requirements. Each TR NOX Annual
allowance shall be held in, deducted
from, or transferred into, out of, or
between Allowance Management
System accounts in accordance with
this subpart.
(6) Limited authorization. A TR NOX
Annual allowance is a limited
authorization to emit one ton of NOX
during the control period in one year.
Such authorization is limited in its use
and duration as follows:
(i) Such authorization shall only be
used in accordance with the TR NOX
Annual Trading Program; and
(ii) Notwithstanding any other
provision of this subpart, the
Administrator has the authority to
terminate or limit the use and duration
of such authorization to the extent the
Administrator determines is necessary
or appropriate to implement any
provision of the Clean Air Act.
(7) Property right. A TR NOX Annual
allowance does not constitute a property
right.
(d) Title V permit requirements. (1) No
title V permit revision shall be required
for any allocation, holding, deduction,
or transfer of TR NOX Annual
allowances in accordance with this
subpart.
(2) A description of whether a unit is
required to monitor and report NOX
emissions using a continuous emission
monitoring system (under subpart H of
part 75 of this chapter), an excepted
monitoring system (under appendices D
and E to part 75 of this chapter), a low
mass emissions excepted monitoring
methodology (under § 75.19 of this
chapter), or an alternative monitoring
system (under subpart E of part 75 of
this chapter) in accordance with
§§ 97.430 through 97.435 may be added
to, or changed in, a title V permit using
minor permit modification procedures
in accordance with §§ 70.7(e)(2) and
71.7(e)(1) of this chapter, provided that
the requirements applicable to the
described monitoring and reporting (as
added or changed, respectively) are
already incorporated in such permit.
This paragraph explicitly provides that
the addition of, or change to, a unit’s
description as described in the prior
sentence is eligible for minor permit
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48387
modification procedures in accordance
with §§ 70.7(e)(2)(i)(B) and
71.7(e)(1)(i)(B) of this chapter.
(e) Additional recordkeeping and
reporting requirements. (1) Unless
otherwise provided, the owners and
operators of each TR NOX Annual
source and each TR NOX Annual unit at
the source shall keep on site at the
source each of the following documents
(in hardcopy or electronic format) for a
period of 5 years from the date the
document is created. This period may
be extended for cause, at any time
before the end of 5 years, in writing by
the Administrator.
(i) The certificate of representation
under § 97.416 for the designated
representative for the source and each
TR NOX Annual unit at the source and
all documents that demonstrate the
truth of the statements in the certificate
of representation; provided that the
certificate and documents shall be
retained on site at the source beyond
such 5-year period until such certificate
of representation and documents are
superseded because of the submission of
a new certificate of representation under
§ 97.416 changing the designated
representative.
(ii) All emissions monitoring
information, in accordance with this
subpart.
(iii) Copies of all reports, compliance
certifications, and other submissions
and all records made or required under,
or to demonstrate compliance with the
requirements of, the TR NOX Annual
Trading Program.
(2) The designated representative of a
TR NOX Annual source and each TR
NOX Annual unit at the source shall
make all submissions required under
the TR NOX Annual Trading Program,
except as provided in § 97.418. This
requirement does not change, create an
exemption from, or or otherwise affect
the responsible official submission
requirements under a title V operating
permit program in parts 70 and 71 of
this chapter.
(f) Liability. (1) Any provision of the
TR NOX Annual Trading Program that
applies to a TR NOX Annual source or
the designated representative of a TR
NOX Annual source shall also apply to
the owners and operators of such source
and of the TR NOX Annual units at the
source.
(2) Any provision of the TR NOX
Annual Trading Program that applies to
a TR NOX Annual unit or the designated
representative of a TR NOX Annual unit
shall also apply to the owners and
operators of such unit.
(g) Effect on other authorities. No
provision of the TR NOX Annual
Trading Program or exemption under
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§ 97.405 shall be construed as
exempting or excluding the owners and
operators, and the designated
representative, of a TR NOX Annual
source or TR NOX Annual unit from
compliance with any other provision of
the applicable, approved State
implementation plan, a federally
enforceable permit, or the Clean Air Act.
§ 97.407
Computation of time.
(a) Unless otherwise stated, any time
period scheduled, under the TR NOX
Annual Trading Program, to begin on
the occurrence of an act or event shall
begin on the day the act or event occurs.
(b) Unless otherwise stated, any time
period scheduled, under the TR NOX
Annual Trading Program, to begin
before the occurrence of an act or event
shall be computed so that the period
ends the day before the act or event
occurs.
(c) Unless otherwise stated, if the final
day of any time period, under the TR
NOX Annual Trading Program, is not a
business day, the time period shall be
extended to the next business day.
§ 97.408 Administrative appeal
procedures.
The administrative appeal procedures
for decisions of the Administrator under
Alabama .......................................................................................................................................
Georgia ........................................................................................................................................
Illinois ...........................................................................................................................................
Indiana .........................................................................................................................................
Iowa .............................................................................................................................................
Kansas .........................................................................................................................................
Kentucky ......................................................................................................................................
Maryland ......................................................................................................................................
Michigan .......................................................................................................................................
Minnesota ....................................................................................................................................
Missouri ........................................................................................................................................
Nebraska ......................................................................................................................................
New Jersey ..................................................................................................................................
New York .....................................................................................................................................
North Carolina ..............................................................................................................................
Ohio .............................................................................................................................................
Pennsylvania ................................................................................................................................
South Carolina .............................................................................................................................
Tennessee ...................................................................................................................................
Texas ...........................................................................................................................................
Virginia .........................................................................................................................................
West Virginia ................................................................................................................................
Wisconsin .....................................................................................................................................
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Alabama .......................................................................................................................................
Georgia ........................................................................................................................................
Illinois ...........................................................................................................................................
Indiana .........................................................................................................................................
Iowa .............................................................................................................................................
Kansas .........................................................................................................................................
Kentucky ......................................................................................................................................
Maryland ......................................................................................................................................
Michigan .......................................................................................................................................
Minnesota ....................................................................................................................................
Missouri ........................................................................................................................................
Nebraska ......................................................................................................................................
New Jersey ..................................................................................................................................
New York .....................................................................................................................................
North Carolina ..............................................................................................................................
Ohio .............................................................................................................................................
Pennsylvania ................................................................................................................................
South Carolina .............................................................................................................................
Tennessee ...................................................................................................................................
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§ 97.410 State NOX Annual trading
budgets, new unit set-asides, Indian
country new unit set-aside, and variability
limits.
(a) The State NOX Annual trading
budgets, new unit set-asides, and Indian
country new unit set-asides for
allocations of TR NOX Annual
allowances for the control periods in
2012 and thereafter are as follows:
72,691
62,010
47,872
109,726
38,335
30,714
85,086
16,633
60,193
29,572
52,374
26,440
7,266
17,543
50,587
92,703
119,986
32,498
35,703
133,595
33,242
59,472
31,628
NOX Annual
trading budget
(tons)* for
2014 and
thereafter
State
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§ 97.409
NOX Annual
trading budget
(tons)* for
2012 and
2013
State
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the TR NOX Annual Trading Program
are set forth in part 78 of this chapter.
Frm 00182
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71,962
40,540
47,872
108,424
37,498
25,560
77,238
16,574
57,812
29,572
48,717
26,440
7,266
17,543
41,553
87,493
119,194
32,498
19,337
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08AUR2
New unit setaside (tons)
for 2012 and
2013
1,454
1,240
3,830
3,292
729
583
3,403
333
1,144
561
1,571
1,825
145
508
2,984
1,854
2,400
617
714
3,874
1,662
2,974
1,866
New unit setaside (tons)
for 2014 and
thereafter
1,439
811
3,830
3,253
712
485
3,090
331
1,098
561
1,462
1,825
145
508
2,451
1,750
2,384
617
387
Indian country
new unit setaside (tons)
for 2012 and
2013
........................
........................
........................
........................
38
31
........................
........................
60
30
........................
26
........................
18
51
........................
........................
33
........................
134
........................
........................
32
Indian country
new unit setaside (tons)
for 2014 and
thereafter
........................
........................
........................
........................
38
26
........................
........................
58
30
........................
26
........................
18
42
........................
........................
33
........................
Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
NOX Annual
trading budget
(tons)* for
2014 and
thereafter
State
Texas ...........................................................................................................................................
Virginia .........................................................................................................................................
West Virginia ................................................................................................................................
Wisconsin .....................................................................................................................................
133,595
33,242
54,582
30,398
New unit setaside (tons)
for 2014 and
thereafter
3,874
1,662
2,729
1,794
48389
Indian country
new unit setaside (tons)
for 2014 and
thereafter
134
........................
........................
30
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-aside and does not include the
variability limit.
(b) The States’ variability limits for
the State NOX Annual trading budgets
for the control periods in 2012 and
thereafter are as follows:
Variability
limits
for 2012 and
2013
State
Alabama ...................................................................................................................................................................
Georgia ....................................................................................................................................................................
Illinois .......................................................................................................................................................................
Indiana .....................................................................................................................................................................
Iowa .........................................................................................................................................................................
Kansas .....................................................................................................................................................................
Kentucky ..................................................................................................................................................................
Maryland ..................................................................................................................................................................
Michigan ...................................................................................................................................................................
Minnesota ................................................................................................................................................................
Missouri ....................................................................................................................................................................
Nebraska ..................................................................................................................................................................
New Jersey ..............................................................................................................................................................
New York .................................................................................................................................................................
North Carolina ..........................................................................................................................................................
Ohio .........................................................................................................................................................................
Pennsylvania ............................................................................................................................................................
South Carolina .........................................................................................................................................................
Tennessee ...............................................................................................................................................................
Texas .......................................................................................................................................................................
Virginia .....................................................................................................................................................................
West Virginia ............................................................................................................................................................
Wisconsin .................................................................................................................................................................
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§ 97.411 Timing requirements for TR NOX
Annual allowance allocations.
(a) Existing units. (1) TR NOX Annual
allowances are allocated, for the control
periods in 2012 and each year
thereafter, as provided in a notice of
data availability issued by the
Administrator. Providing an allocation
to a unit in such notice does not
constitute a determination that the unit
is a TR NOX Annual unit, and not
providing an allocation to a unit in such
notice does not constitute a
determination that the unit is not a TR
NOX Annual unit.
(2) Notwithstanding paragraph (a)(1)
of this section, if a unit provided an
allocation in the notice of data
availability issued under paragraph
(a)(1) of this section does not operate,
starting after 2011, during the control
period in two consecutive years, such
unit will not be allocated the TR NOX
Annual allowances provided in such
notice for the unit for the control
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periods in the fifth year after the first
such year and in each year after that
fifth year. All TR NOX Annual
allowances that would otherwise have
been allocated to such unit will be
allocated to the new unit set-aside for
the State where such unit is located and
for the respective years involved. If such
unit resumes operation, the
Administrator will allocate TR NOX
Annual allowances to the unit in
accordance with paragraph (b) of this
section.
(b) New units. (1) New unit set-asides.
(i) By June 1, 2012 and June 1 of each
year thereafter, the Administrator will
calculate the TR NOX Annual allowance
allocation to each TR NOX Annual unit
in a State, in accordance with
§ 97.412(a)(2) through (7) and (12), for
the control period in the year of the
applicable calculation deadline under
this paragraph and will promulgate a
notice of data availability of the results
of the calculations.
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13,084
11,162
8,617
19,751
6,900
5,529
15,315
2,994
10,835
5,323
9,427
4,759
1,308
3,158
9,106
16,687
21,597
5,850
6,427
24,047
5,984
10,705
5,693
Variability
limits
for 2014 and
thereafter
12,953
7,297
8,617
19,516
6,750
4,601
13,903
2,983
10,406
5,323
8,769
4,759
1,308
3,158
7,480
15,749
21,455
5,850
3,481
24,047
5,984
9,825
5,472
(ii) For each notice of data availability
required in paragraph (b)(1)(i) of this
section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(1)(i) of this section and shall be
limited to addressing whether the
calculations (including the
identification of the TR NOX Annual
units) are in accordance with
§ 97.412(a)(2) through (7) and (12) and
§§ 97.406(b)(2) and 97.430 through
97.435.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(1)(ii)(A) of this section. By August 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(1)(i) of this section, the
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Administrator will promulgate a notice
of data availability of any adjustments
that the Administrator determines to be
necessary with regard to allocations
under § 97.412(a)(2) through (7) and (12)
and the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(1)(ii)(A)
of this section.
(iii) If the new unit set-aside for such
control period contains any TR NOX
Annual allowances that have not been
allocated in the applicable notice of data
availability required in paragraph
(b)(1)(ii) of this section, the
Administrator will promulgate, by
December 15 immediately after such
notice, a notice of data availability that
identifies any TR NOX Annual units that
commenced commercial operation
during the period starting January 1 of
the year before the year of such control
period and ending November 30 of year
of such control period.
(iv) For each notice of data
availability required in paragraph
(b)(1)(iii) of this section, the
Administrator will provide an
opportunity for submission of objections
to the identification of TR NOX annual
units in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(1)(iii) of this section and shall be
limited to addressing whether the
identification of TR NOX annual units in
such notice is in accordance with
paragraph (b)(1)(iii) of this section.
(B) The Administrator will adjust the
identification of TR NOX Annual units
in the each notice of data availability
required in paragraph (b)(1)(iii) of this
section to the extent necessary to ensure
that it is in accordance with paragraph
(b)(1)(iii) of this section and will
calculate the TR NOX Annual allowance
allocation to each TR NOX Annual unit
in accordance with § 97.412(a)(9), (10),
and (12) and §§ 97.406(b)(2) and 97.430
through 97.435. By February 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(1)(iii) of this section,
the Administrator will promulgate a
notice of data availability of any
adjustments of the identification of TR
NOX Annual units that the
Administrator determines to be
necessary, the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(1)(iv)(A)
of this section, and the results of such
calculations.
(v) To the extent any TR NOX Annual
allowances are added to the new unit
set-aside after promulgation of each
notice of data availability required in
paragraph (b)(1)(iv) of this section, the
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Administrator will promulgate
additional notices of data availability, as
deemed appropriate, of the allocation of
such TR NOX Annual allowances in
accordance with § 97.412(a)(10).
(2) Indian country new unit setasides. (i) By June 1, 2012 and June 1
of each year thereafter, the
Administrator will calculate the TR
NOX Annual allowance allocation to
each TR NOX Annual unit in Indian
country within the borders of a State, in
accordance with § 97.412(b)(2) through
(7) and (12), for the control period in the
year of the applicable calculation
deadline under this paragraph and will
promulgate a notice of data availability
of the results of the calculations.
(ii) For each notice of data availability
required in paragraph (b)(2)(i) of this
section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(2)(i) of this section and shall be
limited to addressing whether the
calculations (including the
identification of the TR NOX Annual
units) are in accordance with
§ 97.412(b)(2) through (7) and (12) and
§§ 97.406(b)(2) and 97.430 through
97.435.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(2)(ii)(A) of this section. By August 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(i) of this section, the
Administrator will promulgate a notice
of data availability of any adjustments
that the Administrator determines to be
necessary with regard to allocations
under § 97.412(b)(2) through (7) and (12)
and the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(2)(ii)(A)
of this section.
(iii) If the Indian country new unit
set-aside for such control period
contains any TR NOX Annual
allowances that have not been allocated
in the applicable notice of data
availability required in paragraph
(b)(2)(ii) of this section, the
Administrator will promulgate, by
December 15 immediately after such
notice, a notice of data availability that
identifies any TR NOX Annual units that
commenced commercial operation
during the period starting January 1 of
the year before the year of such control
period and ending November 30 of year
of such control period.
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(iv) For each notice of data
availability required in paragraph
(b)(2)(iii) of this section, the
Administrator will provide an
opportunity for submission of objections
to the identification of TR NOX annual
units in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(2)(iii) of this section and shall be
limited to addressing whether the
identification of TR NOX annual units in
such notice is in accordance with
paragraph (b)(2)(iii) of this section.
(B) The Administrator will adjust the
identification of TR NOX Annual units
in the each notice of data availability
required in paragraph (b)(2)(iii) of this
section to the extent necessary to ensure
that it is in accordance with paragraph
(b)(2)(iii) of this section and will
calculate the TR NOX Annual allowance
allocation to each TR NOX Annual unit
in accordance with § 97.412(b)(9), (10),
and (12) and §§ 97.406(b)(2) and 97.430
through 97.435. By February 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(iii) of this section,
the Administrator will promulgate a
notice of data availability of any
adjustments of the identification of TR
NOX Annual units that the
Administrator determines to be
necessary, the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(2)(iv)(A)
of this section, and the results of such
calculations.
(v) To the extent any TR NOX Annual
allowances are added to the Indian
country new unit set-aside after
promulgation of each notice of data
availability required in paragraph
(b)(2)(iv) of this section, the
Administrator will promulgate
additional notices of data availability, as
deemed appropriate, of the allocation of
such TR NOX Annual allowances in
accordance with § 97.412(b)(10).
(c) Units incorrectly allocated TR NOX
Annual allowances. (1) For each control
period in 2012 and thereafter, if the
Administrator determines that TR NOX
Annual allowances were allocated
under paragraph (a) of this section, or
under a provision of a SIP revision
approved under § 52.38(a)(3), (4), or (5)
of this chapter, where such control
period and the recipient are covered by
the provisions of paragraph (c)(1)(i) of
this section or were allocated under
§ 97.412(a)(2) through (7), (9), and (12)
and (b)(2) through (7), (9), and (12), or
under a provision of a SIP revision
approved under § 52.38(a)(4) or (5) of
this chapter, where such control period
and the recipient are covered by the
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provisions of paragraph (c)(1)(ii) of this
section, then the Administrator will
notify the designated representative of
the recipient and will act in accordance
with the procedures set forth in
paragraphs (c)(2) through (5) of this
section:
(i)(A) The recipient is not actually a
TR NOX Annual unit under § 97.404 as
of January 1, 2012 and is allocated TR
NOX Annual allowances for such
control period or, in the case of an
allocation under a provision of a SIP
revision approved under § 52.38(a)(3),
(4), or (5) of this chapter, the recipient
is not actually a TR NOX Annual unit
as of January 1, 2012 and is allocated TR
NOX Annual allowances for such
control period that the SIP revision
provides should be allocated only to
recipients that are TR NOX Annual units
as of January 1, 2012; or
(B) The recipient is not located as of
January 1 of the control period in the
State from whose NOX Annual trading
budget the TR NOX Annual allowances
allocated under paragraph (a) of this
section, or under a provision of a SIP
revision approved under § 52.38(a)(3),
(4), or (5) of this chapter, were allocated
for such control period.
(ii) The recipient is not actually a TR
NOX Annual unit under § 97.404 as of
January 1 of such control period and is
allocated TR NOX Annual allowances
for such control period or, in the case
of an allocation under a provision of a
SIP revision approved under
§ 52.38(a)(3), (4), or (5) of this chapter,
the recipient is not actually a TR NOX
Annual unit as of January 1 of such
control period and is allocated TR NOX
Annual allowances for such control
period that the SIP revision provides
should be allocated only to recipients
that are TR NOX Annual units as of
January 1 of such control period.
(2) Except as provided in paragraph
(c)(3) or (4) of this section, the
Administrator will not record such TR
NOX Annual allowances under § 97.421.
(3) If the Administrator already
recorded such TR NOX Annual
allowances under § 97.421 and if the
Administrator makes the determination
under paragraph (c)(1) of this section
before making deductions for the source
that includes such recipient under
§ 97.424(b) for such control period, then
the Administrator will deduct from the
account in which such TR NOX Annual
allowances were recorded an amount of
TR NOX Annual allowances allocated
for the same or a prior control period
equal to the amount of such already
recorded TR NOX Annual allowances.
The authorized account representative
shall ensure that there are sufficient TR
NOX Annual allowances in such
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Jkt 223001
account for completion of the
deduction.
(4) If the Administrator already
recorded such TR NOX Annual
allowances under § 97.421 and if the
Administrator makes the determination
under paragraph (c)(1) of this section
after making deductions for the source
that includes such recipient under
§ 97.424(b) for such control period, then
the Administrator will not make any
deduction to take account of such
already recorded TR NOX Annual
allowances.
(5)(i) With regard to the TR NOX
Annual allowances that are not
recorded, or that are deducted as an
incorrect allocation, in accordance with
paragraphs (c)(2) and (3) of this section
for a recipient under paragraph (c)(1)(i)
of this section, the Administrator will:
(A) Transfer such TR NOX Annual
allowances to the new unit set-aside for
such control period for the State from
whose NOX Annual trading budget the
TR NOX Annual allowances were
allocated; or
(B) If the State has a SIP revision
approved under § 52.38(a)(4) or (5)
covering such control period, include
such TR NOX Annual allowances in the
portion of the State NOX Annual trading
budget that may be allocated for such
control period in accordance with such
SIP revision.
(ii) With regard to the TR NOX Annual
allowances that were not allocated from
the Indian country new unit set-aside
for such control period and that are not
recorded, or that are deducted as an
incorrect allocation, in accordance with
paragraphs (c)(2) and (3) of this section
for a recipient under paragraph (c)(1)(ii)
of this paragraph, the Administrator
will:
(A) Transfer such TR NOX Annual
allowances to the new unit set-aside for
such control period; or
(B) If the State has a SIP revision
approved under § 52.38(a)(4) or (5)
covering such control period, include
such TR NOX Annual allowances in the
portion of the State NOX Annual trading
budget that may be allocated for such
control period in accordance with such
SIP revision.
(iii) With regard to the TR NOX
Annual allowances that were allocated
from the Indian country new unit setaside for such control period and that
are not recorded, or that are deducted as
an incorrect allocation, in accordance
with paragraphs (c)(2) and (3) of this
section for a recipient under paragraph
(c)(1)(ii) of this paragraph, the
Administrator will transfer such TR
NOX Annual allowances to the Indian
country new unit set-aside for such
control period.
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48391
§ 97.412 TR NOX Annual allowance
allocations to new units.
(a) For each control period in 2012
and thereafter and for the TR NOX
Annual units in each State, the
Administrator will allocate TR NOX
Annual allowances to the TR NOX
Annual units as follows:
(1) The TR NOX Annual allowances
will be allocated to the following TR
NOX Annual units, except as provided
in paragraph (a)(10) of this section:
(i) TR NOX Annual units that are not
allocated an amount of TR NOX Annual
allowances in the notice of data
availability issued under § 97.411(a)(1);
(ii) TR NOX Annual units whose
allocation of an amount of TR NOX
Annual allowances for such control
period in the notice of data availability
issued under § 97.411(a)(1) is covered
by § 97.411(c)(2) or (3);
(iii) TR NOX Annual units that are
allocated an amount of TR NOX Annual
allowances for such control period in
the notice of data availability issued
under § 97.411(a)(1), which allocation is
terminated for such control period
pursuant to § 97.411(a)(2), and that
operate during the control period
immediately preceding such control
period; or
(iv) For purposes of paragraph (a)(9)
of this section, TR NOX Annual units
under § 97.411(c)(1)(ii) whose allocation
of an amount of TR NOX Annual
allowances for such control period in
the notice of data availability issued
under § 97.411(b)(1)(ii)(B) is covered by
§ 97.411(c)(2) or (3).
(2) The Administrator will establish a
separate new unit set-aside for the State
for each such control period. Each such
new unit set-aside will be allocated TR
NOX Annual allowances in an amount
equal to the applicable amount of tons
of NOX emissions as set forth in
§ 97.410(a) and will be allocated
additional TR NOX Annual allowances
(if any) in accordance with
§§ 97.411(a)(2) and (c)(5) and paragraph
(b)(10) of this section.
(3) The Administrator will determine,
for each TR NOX Annual unit described
in paragraph (a)(1) of this section, an
allocation of TR NOX Annual
allowances for the later of the following
control periods and for each subsequent
control period:
(i) The control period in 2012;
(ii) The first control period after the
control period in which the TR NOX
Annual unit commences commercial
operation;
(iii) For a unit described in paragraph
(a)(1)(ii) of this section, the first control
period in which the TR NOX Annual
unit operates in the State after operating
in another jurisdiction and for which
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the unit is not already allocated one or
more TR NOX Annual allowances; and
(iv) For a unit described in paragraph
(a)(1)(iii) of this section, the first control
period after the control period in which
the unit resumes operation.
(4)(i) The allocation to each TR NOX
annual unit described in paragraph
(a)(1)(i) through (iii) of this section and
for each control period described in
paragraph (a)(3) of this section will be
an amount equal to the unit’s total tons
of NOX emissions during the
immediately preceding control period.
(ii) The Administrator will adjust the
allocation amount in paragraph (a)(4)(i)
in accordance with paragraphs (a)(5)
through (7) and (12) of this section.
(5) The Administrator will calculate
the sum of the TR NOX Annual
allowances determined for all such TR
NOX Annual units under paragraph
(a)(4)(i) of this section in the State for
such control period.
(6) If the amount of TR NOX Annual
allowances in the new unit set-aside for
the State for such control period is
greater than or equal to the sum under
paragraph (a)(5) of this section, then the
Administrator will allocate the amount
of TR NOX Annual allowances
determined for each such TR NOX
Annual unit under paragraph (a)(4)(i) of
this section.
(7) If the amount of TR NOX Annual
allowances in the new unit set-aside for
the State for such control period is less
than the sum under paragraph (a)(5) of
this section, then the Administrator will
allocate to each such TR NOX Annual
unit the amount of the TR NOX Annual
allowances determined under paragraph
(a)(4)(i) of this section for the unit,
multiplied by the amount of TR NOX
Annual allowances in the new unit setaside for such control period, divided
by the sum under paragraph (a)(5) of
this section, and rounded to the nearest
allowance.
(8) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.411(b)(1)(i) and (ii), of the amount
of TR NOX Annual allowances allocated
under paragraphs (a)(2) through (7) and
(12) of this section for such control
period to each TR NOX Annual unit
eligible for such allocation.
(9) If, after completion of the
procedures under paragraphs (a)(5)
through (8) of this section for such
control period, any unallocated TR NOX
Annual allowances remain in the new
unit set-aside for the State for such
control period, the Administrator will
allocate such TR NOX Annual
allowances as follows—
(i) The Administrator will determine,
for each unit described in paragraph
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Jkt 223001
(a)(1) of this section that commenced
commercial operation during the period
starting January 1 of the year before the
year of such control period and ending
November 30 of year of such control
period, the positive difference (if any)
between the unit’s emissions during
such control period and the amount of
TR NOX Annual allowances referenced
in the notice of data availability
required under § 97.411(b)(1)(ii) for the
unit for such control period;
(ii) The Administrator will determine
the sum of the positive differences
determined under paragraph (a)(9)(i) of
this section;
(iii) If the amount of unallocated TR
NOX Annual allowances remaining in
the new unit set-aside for the State for
such control period is greater than or
equal to the sum determined under
paragraph (a)(9)(ii) of this section, then
the Administrator will allocate the
amount of TR NOX Annual allowances
determined for each such TR NOX
Annual unit under paragraph (a)(9)(i) of
this section; and
(iv) If the amount of unallocated TR
NOX Annual allowances remaining in
the new unit set-aside for the State for
such control period is less than the sum
under paragraph (a)(9)(ii) of this section,
then the Administrator will allocate to
each such TR NOX Annual unit the
amount of the TR NOX Annual
allowances determined under paragraph
(a)(9)(i) of this section for the unit,
multiplied by the amount of unallocated
TR NOX Annual allowances remaining
in the new unit set-aside for such
control period, divided by the sum
under paragraph (a)(9)(ii) of this section,
and rounded to the nearest allowance.
(10) If, after completion of the
procedures under paragraphs (a)(9) and
(12) of this section for such control
period, any unallocated TR NOX Annual
allowances remain in the new unit setaside for the State for such control
period, the Administrator will allocate
to each TR NOX Annual unit that is in
the State, is allocated an amount of TR
NOX Annual allowances in the notice of
data availability issued under
§ 97.411(a)(1), and continues to be
allocated TR NOX Annual allowances
for such control period in accordance
with § 97.411(a)(2), an amount of TR
NOX Annual allowances equal to the
following: the total amount of such
remaining unallocated TR NOX Annual
allowances in such new unit set-aside,
multiplied by the unit’s allocation
under § 97.411(a) for such control
period, divided by the remainder of the
amount of tons in the applicable State
NOX Annual trading budget minus the
sum of the amounts of tons in such new
unit set-aside and the Indian country
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new unit set-aside for the State for such
control period, and rounded to the
nearest allowance.
(11) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.411(b)(1)(iii), (iv), and (v), of the
amount of TR NOX Annual allowances
allocated under paragraphs (a)(9), (10),
and (12) of this section for such control
period to each TR NOX Annual unit
eligible for such allocation.
(12)(i) Notwithstanding the
requirements of paragraphs (a)(2)
through (11) of this section, if the
calculations of allocations of a new unit
set-aside for a control period in a given
year under paragraph (a)(7) of this
section, paragraphs (a)(6) and (9)(iv) of
this section, or paragraphs (a)(6), (9)(iii),
and (10) of this section would otherwise
result in total allocations of such new
unit set-aside exceeding the total
amount of such new unit set-aside, then
the Administrator will adjust the results
of the calculations under paragraph
(a)(7), (9)(iv), or (10) of this section, as
applicable, as follows. The
Administrator will list the TR NOX
Annual units in descending order based
on the amount of such units’ allocations
under paragraph (a)(7), (9)(iv), or (10) of
this section, as applicable, and, in cases
of equal allocation amounts, in
alphabetical order of the relevant
source’s name and numerical order of
the relevant unit’s identification
number, and will reduce each unit’s
allocation under paragraph (a)(7),
(9)(iv), or (10) of this section, as
applicable, by one TR NOX Annual
allowance (but not below zero) in the
order in which the units are listed and
will repeat this reduction process as
necessary, until the total allocations of
such new unit set-aside equal the total
amount of such new unit set-aside.
(ii) Notwithstanding the requirements
of paragraphs (a)(10) and (11) of this
section, if the calculations of allocations
of a new unit set-aside for a control
period in a given year under paragraphs
(a)(6), (9)(iii), and (10) of this section
would otherwise result in a total
allocations of such new unit set-aside
less than the total amount of such new
unit set-aside, then the Administrator
will adjust the results of the calculations
under paragraph (a)(10) of this section,
as follows. The Administrator will list
the TR NOX Annual units in descending
order based on the amount of such
units’ allocations under paragraph
(a)(10) of this section and, in cases of
equal allocation amounts, in
alphabetical order of the relevant
source’s name and numerical order of
the relevant unit’s identification
number, and will increase each unit’s
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allocation under paragraph (a)(10) of
this section by one TR NOX Annual
allowance in the order in which the
units are listed and will repeat this
increase process as necessary, until the
total allocations of such new unit setaside equal the total amount of such
new unit set-aside.
(b) For each control period in 2012
and thereafter and for the TR NOX
Annual units located in Indian country
within the borders of each State, the
Administrator will allocate TR NOX
Annual allowances to the TR NOX
Annual units as follows:
(1) The TR NOX Annual allowances
will be allocated to the following TR
NOX Annual units, except as provided
in paragraph (b)(10) of this section:
(i) TR NOX Annual units that are not
allocated an amount of TR NOX Annual
allowances in the notice of data
availability issued under § 97.411(a)(1);
or
(ii) For purposes of paragraph (b)(9) of
this section, TR NOX Annual units
under § 97.411(c)(1)(ii) whose allocation
of an amount of TR NOX Annual
allowances for such control period in
the notice of data availability issued
under § 97.411(b)(2)(ii)(B) is covered by
§ 97.411(c)(2) or (3).
(2) The Administrator will establish a
separate Indian country new unit setaside for the State for each such control
period. Each such Indian country new
unit set-aside will be allocated TR NOX
Annual allowances in an amount equal
to the applicable amount of tons of NOX
emissions as set forth in § 97.410(a) and
will be allocated additional TR NOX
Annual allowances (if any) in
accordance with § 97.411(c)(5).
(3) The Administrator will determine,
for each TR NOX Annual unit described
in paragraph (b)(1) of this section, an
allocation of TR NOX Annual
allowances for the later of the following
control periods and for each subsequent
control period:
(i) The control period in 2012; and
(ii) The first control period after the
control period in which the TR NOX
Annual unit commences commercial
operation.
(4)(i) The allocation to each TR NOX
annual unit described in paragraph
(b)(1)(i) of this section and for each
control period described in paragraph
(b)(3) of this section will be an amount
equal to the unit’s total tons of NOX
emissions during the immediately
preceding control period.
(ii) The Administrator will adjust the
allocation amount in paragraph (b)(4)(i)
in accordance with paragraphs (b)(5)
through (7) and (12) of this section.
(5) The Administrator will calculate
the sum of the TR NOX Annual
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allowances determined for all such TR
NOX Annual units under paragraph
(b)(4)(i) of this section in Indian country
within the borders of the State for such
control period.
(6) If the amount of TR NOX Annual
allowances in the Indian country new
unit set-aside for the State for such
control period is greater than or equal to
the sum under paragraph (b)(5) of this
section, then the Administrator will
allocate the amount of TR NOX Annual
allowances determined for each such TR
NOX Annual unit under paragraph
(b)(4)(i) of this section.
(7) If the amount of TR NOX Annual
allowances in the Indian country new
unit set-aside for the State for such
control period is less than the sum
under paragraph (b)(5) of this section,
then the Administrator will allocate to
each such TR NOX Annual unit the
amount of the TR NOX Annual
allowances determined under paragraph
(b)(4)(i) of this section for the unit,
multiplied by the amount of TR NOX
Annual allowances in the Indian
country new unit set-aside for such
control period, divided by the sum
under paragraph (b)(5) of this section,
and rounded to the nearest allowance.
(8) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.411(b)(2)(i) and (ii), of the amount
of TR NOX Annual allowances allocated
under paragraphs (b)(2) through (7) and
(12) of this section for such control
period to each TR NOX Annual unit
eligible for such allocation.
(9) If, after completion of the
procedures under paragraphs (b)(5)
through (8) of this section for such
control period, any unallocated TR NOX
Annual allowances remain in the Indian
country new unit set-aside for the State
for such control period, the
Administrator will allocate such TR
NOX Annual allowances as follows—
(i) The Administrator will determine,
for each unit described in paragraph
(b)(1) of this section that commenced
commercial operation during the period
starting January 1 of the year before the
year of such control period and ending
November 30 of year of such control
period, the positive difference (if any)
between the unit’s emissions during
such control period and the amount of
TR NOX Annual allowances referenced
in the notice of data availability
required under § 97.411(b)(2)(ii) for the
unit for such control period;
(ii) The Administrator will determine
the sum of the positive differences
determined under paragraph (b)(9)(i) of
this section;
(iii) If the amount of unallocated TR
NOX Annual allowances remaining in
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48393
the Indian country new unit set-aside
for the State for such control period is
greater than or equal to the sum
determined under paragraph (b)(9)(ii) of
this section, then the Administrator will
allocate the amount of TR NOX Annual
allowances determined for each such TR
NOX Annual unit under paragraph
(b)(9)(i) of this section; and
(iv) If the amount of unallocated TR
NOX Annual allowances remaining in
the Indian country new unit set-aside
for the State for such control period is
less than the sum under paragraph
(b)(9)(ii) of this section, then the
Administrator will allocate to each such
TR NOX Annual unit the amount of the
TR NOX Annual allowances determined
under paragraph (b)(9)(i) of this section
for the unit, multiplied by the amount
of unallocated TR NOX Annual
allowances remaining in the Indian
country new unit set-aside for such
control period, divided by the sum
under paragraph (b)(9)(ii) of this section,
and rounded to the nearest allowance.
(10) If, after completion of the
procedures under paragraphs (b)(9) and
(12) of this section for such control
period, any unallocated TR NOX Annual
allowances remain in the Indian country
new unit set-aside for the State for such
control period, the Administrator will:
(i) Transfer such unallocated TR NOX
Annual allowances to the new unit setaside for the State for such control
period; or
(ii) If the State has a SIP revision
approved under § 52.38(a)(4) or (5)
covering such control period, include
such unallocated TR NOX Annual
allowances in the portion of the State
NOX Annual trading budget that may be
allocated for such control period in
accordance with such SIP revision.
(11) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.411(b)(2)(iii), (iv), and (v), of the
amount of TR NOX Annual allowances
allocated under paragraphs (b)(9), (10),
and (12) of this section for such control
period to each TR NOX Annual unit
eligible for such allocation.
(12)(i) Notwithstanding the
requirements of paragraphs (b)(2)
through (11) of this section, if the
calculations of allocations of an Indian
country new unit set-aside for a control
period in a given year under paragraph
(b)(7) of this section, paragraphs (b)(6)
and (9)(iv) of this section, or paragraphs
(b)(6), (9)(iii), and (10) of this section
would otherwise result in total
allocations of such Indian country new
unit set-aside exceeding the total
amount of such Indian country new unit
set-aside, then the Administrator will
adjust the results of the calculations
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under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, as follows.
The Administrator will list the TR NOX
Annual units in descending order based
on the amount of such units’ allocations
under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, and, in cases
of equal allocation amounts, in
alphabetical order of the relevant
source’s name and numerical order of
the relevant unit’s identification
number, and will reduce each unit’s
allocation under paragraph (b)(7),
(9)(iv), or (10) of this section, as
applicable, by one TR NOX Annual
allowance (but not below zero) in the
order in which the units are listed and
will repeat this reduction process as
necessary, until the total allocations of
such Indian country new unit set-aside
equal the total amount of such Indian
country new unit set-aside.
(ii) Notwithstanding the requirements
of paragraphs (b)(10) and (11) of this
section, if the calculations of allocations
of an Indian country new unit set-aside
for a control period in a given year
under paragraphs (b)(6), (9)(iii), and (10)
of this section would otherwise result in
a total allocations of such Indian
country new unit set-aside less than the
total amount of such Indian country
new unit set-aside, then the
Administrator will adjust the results of
the calculations under paragraph (b)(10)
of this section, as follows. The
Administrator will list the TR NOX
Annual units in descending order based
on the amount of such units’ allocations
under paragraph (b)(10) of this section
and, in cases of equal allocation
amounts, in alphabetical order of the
relevant source’s name and numerical
order of the relevant unit’s
identification number, and will increase
each unit’s allocation under paragraph
(b)(10) of this section by one TR NOX
Annual allowance in the order in which
the units are listed and will repeat this
increase process as necessary, until the
total allocations of such Indian country
new unit set-aside equal the total
amount of such Indian country new unit
set-aside.
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§ 97.413 Authorization of designated
representative and alternate designated
representative.
(a) Except as provided under § 97.415,
each TR NOX Annual source, including
all TR NOX Annual units at the source,
shall have one and only one designated
representative, with regard to all matters
under the TR NOX Annual Trading
Program.
(1) The designated representative
shall be selected by an agreement
binding on the owners and operators of
the source and all TR NOX Annual units
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at the source and shall act in accordance
with the certification statement in
§ 97.416(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 97.416:
(i) The designated representative shall
be authorized and shall represent and,
by his or her representations, actions,
inactions, or submissions, legally bind
each owner and operator of the source
and each TR NOX Annual unit at the
source in all matters pertaining to the
TR NOX Annual Trading Program,
notwithstanding any agreement between
the designated representative and such
owners and operators; and
(ii) The owners and operators of the
source and each TR NOX Annual unit at
the source shall be bound by any
decision or order issued to the
designated representative by the
Administrator regarding the source or
any such unit.
(b) Except as provided under § 97.415,
each TR NOX Annual source may have
one and only one alternate designated
representative, who may act on behalf of
the designated representative. The
agreement by which the alternate
designated representative is selected
shall include a procedure for
authorizing the alternate designated
representative to act in lieu of the
designated representative.
(1) The alternate designated
representative shall be selected by an
agreement binding on the owners and
operators of the source and all TR NOX
Annual units at the source and shall act
in accordance with the certification
statement in § 97.416(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 97.416,
(i) The alternate designated
representative shall be authorized;
(ii) Any representation, action,
inaction, or submission by the alternate
designated representative shall be
deemed to be a representation, action,
inaction, or submission by the
designated representative; and
(iii) The owners and operators of the
source and each TR NOX Annual unit at
the source shall be bound by any
decision or order issued to the alternate
designated representative by the
Administrator regarding the source or
any such unit.
(c) Except in this section, § 97.402,
and §§ 97.414 through 97.418, whenever
the term ‘‘designated representative’’ (as
distinguished from the term ‘‘common
designated representative’’) is used in
this subpart, the term shall be construed
to include the designated representative
or any alternate designated
representative.
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§ 97.414 Responsibilities of designated
representative and alternate designated
representative.
(a) Except as provided under § 97.418
concerning delegation of authority to
make submissions, each submission
under the TR NOX Annual Trading
Program shall be made, signed, and
certified by the designated
representative or alternate designated
representative for each TR NOX Annual
source and TR NOX Annual unit for
which the submission is made. Each
such submission shall include the
following certification statement by the
designated representative or alternate
designated representative: ‘‘I am
authorized to make this submission on
behalf of the owners and operators of
the source or units for which the
submission is made. I certify under
penalty of law that I have personally
examined, and am familiar with, the
statements and information submitted
in this document and all its
attachments. Based on my inquiry of
those individuals with primary
responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(b) The Administrator will accept or
act on a submission made for a TR NOX
Annual source or a TR NOX Annual unit
only if the submission has been made,
signed, and certified in accordance with
paragraph (a) of this section and
§ 97.418.
§ 97.415 Changing designated
representative and alternate designated
representative; changes in owners and
operators; changes in units at the source.
(a) Changing designated
representative. The designated
representative may be changed at any
time upon receipt by the Administrator
of a superseding complete certificate of
representation under § 97.416.
Notwithstanding any such change, all
representations, actions, inactions, and
submissions by the previous designated
representative before the time and date
when the Administrator receives the
superseding certificate of representation
shall be binding on the new designated
representative and the owners and
operators of the TR NOX Annual source
and the TR NOX Annual units at the
source.
(b) Changing alternate designated
representative. The alternate designated
representative may be changed at any
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time upon receipt by the Administrator
of a superseding complete certificate of
representation under § 97.416.
Notwithstanding any such change, all
representations, actions, inactions, and
submissions by the previous alternate
designated representative before the
time and date when the Administrator
receives the superseding certificate of
representation shall be binding on the
new alternate designated representative,
the designated representative, and the
owners and operators of the TR NOX
Annual source and the TR NOX Annual
units at the source.
(c) Changes in owners and operators.
(1) In the event an owner or operator of
a TR NOX Annual source or a TR NOX
Annual unit at the source is not
included in the list of owners and
operators in the certificate of
representation under § 97.416, such
owner or operator shall be deemed to be
subject to and bound by the certificate
of representation, the representations,
actions, inactions, and submissions of
the designated representative and any
alternate designated representative of
the source or unit, and the decisions
and orders of the Administrator, as if
the owner or operator were included in
such list.
(2) Within 30 days after any change in
the owners and operators of a TR NOX
Annual source or a TR NOX Annual unit
at the source, including the addition or
removal of an owner or operator, the
designated representative or any
alternate designated representative shall
submit a revision to the certificate of
representation under § 97.416 amending
the list of owners and operators to
reflect the change.
(d) Changes in units at the source.
Within 30 days of any change in which
units are located at a TR NOX Annual
source (including the addition or
removal of a unit), the designated
representative or any alternate
designated representative shall submit a
certificate of representation under
§ 97.416 amending the list of units to
reflect the change.
(1) If the change is the addition of a
unit that operated (other than for
purposes of testing by the manufacturer
before initial installation) before being
located at the source, then the certificate
of representation shall identify, in a
format prescribed by the Administrator,
the entity from whom the unit was
purchased or otherwise obtained
(including name, address, telephone
number, and facsimile number (if any)),
the date on which the unit was
purchased or otherwise obtained, and
the date on which the unit became
located at the source.
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(2) If the change is the removal of a
unit, then the certificate of
representation shall identify, in a format
prescribed by the Administrator, the
entity to which the unit was sold or that
otherwise obtained the unit (including
name, address, telephone number, and
facsimile number (if any)), the date on
which the unit was sold or otherwise
obtained, and the date on which the
unit became no longer located at the
source.
§ 97.416
Certificate of representation.
(a) A complete certificate of
representation for a designated
representative or an alternate designated
representative shall include the
following elements in a format
prescribed by the Administrator:
(1) Identification of the TR NOX
Annual source, and each TR NOX
Annual unit at the source, for which the
certificate of representation is
submitted, including source name,
source category and NAICS code (or, in
the absence of a NAICS code, an
equivalent code), State, plant code,
county, latitude and longitude, unit
identification number and type,
identification number and nameplate
capacity (in MWe, rounded to the
nearest tenth) of each generator served
by each such unit, actual or projected
date of commencement of commercial
operation, and a statement of whether
such source is located in Indian
Country. If a projected date of
commencement of commercial
operation is provided, the actual date of
commencement of commercial
operation shall be provided when such
information becomes available.
(2) The name, address, e-mail address
(if any), telephone number, and
facsimile transmission number (if any)
of the designated representative and any
alternate designated representative.
(3) A list of the owners and operators
of the TR NOX Annual source and of
each TR NOX Annual unit at the source.
(4) The following certification
statements by the designated
representative and any alternate
designated representative—
(i) ‘‘I certify that I was selected as the
designated representative or alternate
designated representative, as applicable,
by an agreement binding on the owners
and operators of the source and each TR
NOX Annual unit at the source.’’
(ii) ‘‘I certify that I have all the
necessary authority to carry out my
duties and responsibilities under the TR
NOX Annual Trading Program on behalf
of the owners and operators of the
source and of each TR NOX Annual unit
at the source and that each such owner
and operator shall be fully bound by my
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48395
representations, actions, inactions, or
submissions and by any decision or
order issued to me by the Administrator
regarding the source or unit.’’
(iii) ‘‘Where there are multiple
holders of a legal or equitable title to, or
a leasehold interest in, a TR NOX
Annual unit, or where a utility or
industrial customer purchases power
from a TR NOX Annual unit under a
life-of-the-unit, firm power contractual
arrangement, I certify that: I have given
a written notice of my selection as the
‘designated representative’ or ‘alternate
designated representative’, as
applicable, and of the agreement by
which I was selected to each owner and
operator of the source and of each TR
NOX Annual unit at the source; and TR
NOX Annual allowances and proceeds
of transactions involving TR NOX
Annual allowances will be deemed to be
held or distributed in proportion to each
holder’s legal, equitable, leasehold, or
contractual reservation or entitlement,
except that, if such multiple holders
have expressly provided for a different
distribution of TR NOX Annual
allowances by contract, TR NOX Annual
allowances and proceeds of transactions
involving TR NOX Annual allowances
will be deemed to be held or distributed
in accordance with the contract.’’
(5) The signature of the designated
representative and any alternate
designated representative and the dates
signed.
(b) Unless otherwise required by the
Administrator, documents of agreement
referred to in the certificate of
representation shall not be submitted to
the Administrator. The Administrator
shall not be under any obligation to
review or evaluate the sufficiency of
such documents, if submitted.
§ 97.417 Objections concerning
designated representative and alternate
designated representative.
(a) Once a complete certificate of
representation under § 97.416 has been
submitted and received, the
Administrator will rely on the certificate
of representation unless and until a
superseding complete certificate of
representation under § 97.416 is
received by the Administrator.
(b) Except as provided in paragraph
(a) of this section, no objection or other
communication submitted to the
Administrator concerning the
authorization, or any representation,
action, inaction, or submission, of a
designated representative or alternate
designated representative shall affect
any representation, action, inaction, or
submission of the designated
representative or alternate designated
representative or the finality of any
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decision or order by the Administrator
under the TR NOX Annual Trading
Program.
(c) The Administrator will not
adjudicate any private legal dispute
concerning the authorization or any
representation, action, inaction, or
submission of any designated
representative or alternate designated
representative, including private legal
disputes concerning the proceeds of TR
NOX Annual allowance transfers.
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§ 97.418 Delegation by designated
representative and alternate designated
representative.
(a) A designated representative may
delegate, to one or more natural persons,
his or her authority to make an
electronic submission to the
Administrator provided for or required
under this subpart.
(b) An alternate designated
representative may delegate, to one or
more natural persons, his or her
authority to make an electronic
submission to the Administrator
provided for or required under this
subpart.
(c) In order to delegate authority to a
natural person to make an electronic
submission to the Administrator in
accordance with paragraph (a) or (b) of
this section, the designated
representative or alternate designated
representative, as appropriate, must
submit to the Administrator a notice of
delegation, in a format prescribed by the
Administrator, that includes the
following elements:
(1) The name, address, e-mail address,
telephone number, and facsimile
transmission number (if any) of such
designated representative or alternate
designated representative;
(2) The name, address, e-mail address,
telephone number, and facsimile
transmission number (if any) of each
such natural person (referred to in this
section as an ‘‘agent’’);
(3) For each such natural person, a list
of the type or types of electronic
submissions under paragraph (a) or (b)
of this section for which authority is
delegated to him or her; and
(4) The following certification
statements by such designated
representative or alternate designated
representative:
(i) ‘‘I agree that any electronic
submission to the Administrator that is
made by an agent identified in this
notice of delegation and of a type listed
for such agent in this notice of
delegation and that is made when I am
a designated representative or alternate
designated representative, as
appropriate, and before this notice of
delegation is superseded by another
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notice of delegation under 40 CFR
97.418(d) shall be deemed to be an
electronic submission by me.’’
(ii) ‘‘Until this notice of delegation is
superseded by another notice of
delegation under 40 CFR 97.418(d), I
agree to maintain an e-mail account and
to notify the Administrator immediately
of any change in my e-mail address
unless all delegation of authority by me
under 40 CFR 97.418 is terminated.’’.
(d) A notice of delegation submitted
under paragraph (c) of this section shall
be effective, with regard to the
designated representative or alternate
designated representative identified in
such notice, upon receipt of such notice
by the Administrator and until receipt
by the Administrator of a superseding
notice of delegation submitted by such
designated representative or alternate
designated representative, as
appropriate. The superseding notice of
delegation may replace any previously
identified agent, add a new agent, or
eliminate entirely any delegation of
authority.
(e) Any electronic submission covered
by the certification in paragraph (c)(4)(i)
of this section and made in accordance
with a notice of delegation effective
under paragraph (d) of this section shall
be deemed to be an electronic
submission by the designated
representative or alternate designated
representative submitting such notice of
delegation.
§ 97.419
[Reserved]
§ 97.420 Establishment of compliance
accounts, assurance accounts, and general
accounts.
(a) Compliance accounts. Upon
receipt of a complete certificate of
representation under § 97.416, the
Administrator will establish a
compliance account for the TR NOX
Annual source for which the certificate
of representation was submitted, unless
the source already has a compliance
account. The designated representative
and any alternate designated
representative of the source shall be the
authorized account representative and
the alternate authorized account
representative respectively of the
compliance account.
(b) Assurance accounts. The
Administrator will establish assurance
accounts for certain owners and
operators and States in accordance with
§ 97.425(b)(3).
(c) General accounts. (1) Application
for general account. (i) Any person may
apply to open a general account, for the
purpose of holding and transferring TR
NOX Annual allowances, by submitting
to the Administrator a complete
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application for a general account. Such
application shall designate one and only
one authorized account representative
and may designate one and only one
alternate authorized account
representative who may act on behalf of
the authorized account representative.
(A) The authorized account
representative and alternate authorized
account representative shall be selected
by an agreement binding on the persons
who have an ownership interest with
respect to TR NOX Annual allowances
held in the general account.
(B) The agreement by which the
alternate authorized account
representative is selected shall include
a procedure for authorizing the alternate
authorized account representative to act
in lieu of the authorized account
representative.
(ii) A complete application for a
general account shall include the
following elements in a format
prescribed by the Administrator:
(A) Name, mailing address, e-mail
address (if any), telephone number, and
facsimile transmission number (if any)
of the authorized account representative
and any alternate authorized account
representative;
(B) An identifying name for the
general account;
(C) A list of all persons subject to a
binding agreement for the authorized
account representative and any alternate
authorized account representative to
represent their ownership interest with
respect to the TR NOX Annual
allowances held in the general account;
(D) The following certification
statement by the authorized account
representative and any alternate
authorized account representative: ‘‘I
certify that I was selected as the
authorized account representative or the
alternate authorized account
representative, as applicable, by an
agreement that is binding on all persons
who have an ownership interest with
respect to TR NOX Annual allowances
held in the general account. I certify that
I have all the necessary authority to
carry out my duties and responsibilities
under the TR NOX Annual Trading
Program on behalf of such persons and
that each such person shall be fully
bound by my representations, actions,
inactions, or submissions and by any
decision or order issued to me by the
Administrator regarding the general
account.’’
(E) The signature of the authorized
account representative and any alternate
authorized account representative and
the dates signed.
(iii) Unless otherwise required by the
Administrator, documents of agreement
referred to in the application for a
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general account shall not be submitted
to the Administrator. The Administrator
shall not be under any obligation to
review or evaluate the sufficiency of
such documents, if submitted.
(2) Authorization of authorized
account representative and alternate
authorized account representative. (i)
Upon receipt by the Administrator of a
complete application for a general
account under paragraph (b)(1) of this
section, the Administrator will establish
a general account for the person or
persons for whom the application is
submitted, and upon and after such
receipt by the Administrator:
(A) The authorized account
representative of the general account
shall be authorized and shall represent
and, by his or her representations,
actions, inactions, or submissions,
legally bind each person who has an
ownership interest with respect to TR
NOX Annual allowances held in the
general account in all matters pertaining
to the TR NOX Annual Trading Program,
notwithstanding any agreement between
the authorized account representative
and such person.
(B) Any alternate authorized account
representative shall be authorized, and
any representation, action, inaction, or
submission by any alternate authorized
account representative shall be deemed
to be a representation, action, inaction,
or submission by the authorized account
representative.
(C) Each person who has an
ownership interest with respect to TR
NOX Annual allowances held in the
general account shall be bound by any
decision or order issued to the
authorized account representative or
alternate authorized account
representative by the Administrator
regarding the general account.
(ii) Except as provided in paragraph
(c)(5) of this section concerning
delegation of authority to make
submissions, each submission
concerning the general account shall be
made, signed, and certified by the
authorized account representative or
any alternate authorized account
representative for the persons having an
ownership interest with respect to TR
NOX Annual allowances held in the
general account. Each such submission
shall include the following certification
statement by the authorized account
representative or any alternate
authorized account representative: ‘‘I
am authorized to make this submission
on behalf of the persons having an
ownership interest with respect to the
TR NOX Annual allowances held in the
general account. I certify under penalty
of law that I have personally examined,
and am familiar with, the statements
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and information submitted in this
document and all its attachments. Based
on my inquiry of those individuals with
primary responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(iii) Except in this section, whenever
the term ‘‘authorized account
representative’’ is used in this subpart,
the term shall be construed to include
the authorized account representative or
any alternate authorized account
representative.
(3) Changing authorized account
representative and alternate authorized
account representative; changes in
persons with ownership interest. (i) The
authorized account representative of a
general account may be changed at any
time upon receipt by the Administrator
of a superseding complete application
for a general account under paragraph
(c)(1) of this section. Notwithstanding
any such change, all representations,
actions, inactions, and submissions by
the previous authorized account
representative before the time and date
when the Administrator receives the
superseding application for a general
account shall be binding on the new
authorized account representative and
the persons with an ownership interest
with respect to the TR NOX Annual
allowances in the general account.
(ii) The alternate authorized account
representative of a general account may
be changed at any time upon receipt by
the Administrator of a superseding
complete application for a general
account under paragraph (c)(1) of this
section. Notwithstanding any such
change, all representations, actions,
inactions, and submissions by the
previous alternate authorized account
representative before the time and date
when the Administrator receives the
superseding application for a general
account shall be binding on the new
alternate authorized account
representative, the authorized account
representative, and the persons with an
ownership interest with respect to the
TR NOX Annual allowances in the
general account.
(iii)(A) In the event a person having
an ownership interest with respect to
TR NOX Annual allowances in the
general account is not included in the
list of such persons in the application
for a general account, such person shall
be deemed to be subject to and bound
by the application for a general account,
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48397
the representation, actions, inactions,
and submissions of the authorized
account representative and any alternate
authorized account representative of the
account, and the decisions and orders of
the Administrator, as if the person were
included in such list.
(B) Within 30 days after any change
in the persons having an ownership
interest with respect to NOX Annual
allowances in the general account,
including the addition or removal of a
person, the authorized account
representative or any alternate
authorized account representative shall
submit a revision to the application for
a general account amending the list of
persons having an ownership interest
with respect to the TR NOX Annual
allowances in the general account to
include the change.
(4) Objections concerning authorized
account representative and alternate
authorized account representative. (i)
Once a complete application for a
general account under paragraph (c)(1)
of this section has been submitted and
received, the Administrator will rely on
the application unless and until a
superseding complete application for a
general account under paragraph (b)(1)
of this section is received by the
Administrator.
(ii) Except as provided in paragraph
(c)(4)(i) of this section, no objection or
other communication submitted to the
Administrator concerning the
authorization, or any representation,
action, inaction, or submission of the
authorized account representative or
any alternate authorized account
representative of a general account shall
affect any representation, action,
inaction, or submission of the
authorized account representative or
any alternate authorized account
representative or the finality of any
decision or order by the Administrator
under the TR NOX Annual Trading
Program.
(iii) The Administrator will not
adjudicate any private legal dispute
concerning the authorization or any
representation, action, inaction, or
submission of the authorized account
representative or any alternate
authorized account representative of a
general account, including private legal
disputes concerning the proceeds of TR
NOX Annual allowance transfers.
(5) Delegation by authorized account
representative and alternate authorized
account representative. (i) An
authorized account representative of a
general account may delegate, to one or
more natural persons, his or her
authority to make an electronic
submission to the Administrator
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provided for or required under this
subpart.
(ii) An alternate authorized account
representative of a general account may
delegate, to one or more natural persons,
his or her authority to make an
electronic submission to the
Administrator provided for or required
under this subpart.
(iii) In order to delegate authority to
a natural person to make an electronic
submission to the Administrator in
accordance with paragraph (c)(5)(i) or
(ii) of this section, the authorized
account representative or alternate
authorized account representative, as
appropriate, must submit to the
Administrator a notice of delegation, in
a format prescribed by the
Administrator, that includes the
following elements:
(A) The name, address, e-mail
address, telephone number, and
facsimile transmission number (if any)
of such authorized account
representative or alternate authorized
account representative;
(B) The name, address, e-mail
address, telephone number, and
facsimile transmission number (if any)
of each such natural person (referred to
in this section as an ‘‘agent’’);
(C) For each such natural person, a
list of the type or types of electronic
submissions under paragraph (c)(5)(i) or
(ii) of this section for which authority is
delegated to him or her;
(D) The following certification
statement by such authorized account
representative or alternate authorized
account representative: ‘‘I agree that any
electronic submission to the
Administrator that is made by an agent
identified in this notice of delegation
and of a type listed for such agent in
this notice of delegation and that is
made when I am an authorized account
representative or alternate authorized
representative, as appropriate, and
before this notice of delegation is
superseded by another notice of
delegation under 40 CFR 97.420(c)(5)(iv)
shall be deemed to be an electronic
submission by me.’’; and
(E) The following certification
statement by such authorized account
representative or alternate authorized
account representative: ‘‘Until this
notice of delegation is superseded by
another notice of delegation under 40
CFR 97.420(c)(5)(iv), I agree to maintain
an e-mail account and to notify the
Administrator immediately of any
change in my e-mail address unless all
delegation of authority by me under 40
CFR 97.420(c)(5) is terminated.’’.
(iv) A notice of delegation submitted
under paragraph (c)(5)(iii) of this section
shall be effective, with regard to the
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authorized account representative or
alternate authorized account
representative identified in such notice,
upon receipt of such notice by the
Administrator and until receipt by the
Administrator of a superseding notice of
delegation submitted by such
authorized account representative or
alternate authorized account
representative, as appropriate. The
superseding notice of delegation may
replace any previously identified agent,
add a new agent, or eliminate entirely
any delegation of authority.
(v) Any electronic submission covered
by the certification in paragraph
(c)(5)(iii)(D) of this section and made in
accordance with a notice of delegation
effective under paragraph (c)(5)(iv) of
this section shall be deemed to be an
electronic submission by the designated
representative or alternate designated
representative submitting such notice of
delegation.
(6) Closing a general account. (i) The
authorized account representative or
alternate authorized account
representative of a general account may
submit to the Administrator a request to
close the account. Such request shall
include a correctly submitted TR NOX
Annual allowance transfer under
§ 97.422 for any TR NOX Annual
allowances in the account to one or
more other Allowance Management
System accounts.
(ii) If a general account has no TR
NOX Annual allowance transfers to or
from the account for a 12-month period
or longer and does not contain any TR
NOX Annual allowances, the
Administrator may notify the authorized
account representative for the account
that the account will be closed after 30
days after the notice is sent. The
account will be closed after the 30-day
period unless, before the end of the 30day period, the Administrator receives a
correctly submitted TR NOX Annual
allowance transfer under § 97.422 to the
account or a statement submitted by the
authorized account representative or
alternate authorized account
representative demonstrating to the
satisfaction of the Administrator good
cause as to why the account should not
be closed.
(d) Account identification. The
Administrator will assign a unique
identifying number to each account
established under paragraph (a), (b), or
(c) of this section.
(e) Responsibilities of authorized
account representative and alternate
authorized account representative. After
the establishment of a compliance
account or general account, the
Administrator will accept or act on a
submission pertaining to the account,
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including, but not limited to,
submissions concerning the deduction
or transfer of TR NOX Annual
allowances in the account, only if the
submission has been made, signed, and
certified in accordance with §§ 97.414(a)
and 97.418 or paragraphs (c)(2)(ii) and
(c)(5) of this section.
§ 97.421 Recordation of TR NOX Annual
allowance allocations and auction results.
(a) By November 7, 2011, the
Administrator will record in each TR
NOX Annual source’s compliance
account the TR NOX Annual allowances
allocated to the TR NOX Annual units
at the source in accordance with
§ 97.411(a) for the control period in
2012.
(b) By November 7, 2011, the
Administrator will record in each TR
NOX Annual source’s compliance
account the TR NOX Annual allowances
allocated to the TR NOX Annual units
at the source in accordance with
§ 97.411(a) for the control period in
2013, unless the State in which the
source is located notifies the
Administrator in writing by October 17,
2011 of the State’s intent to submit to
the Administrator a complete SIP
revision by April 1, 2012 meeting the
requirements of § 52.38(a)(3)(i) through
(iv) of this chapter.
(1) If, by April 1, 2012, the State does
not submit to the Administrator such
complete SIP revision, the
Administrator will record by April 15,
2012 in each TR NOX Annual source’s
compliance account the TR NOX Annual
allowances allocated to the TR NOX
Annual units at the source in
accordance with § 97.411(a) for the
control period in 2013.
(2) If the State submits to the
Administrator by April 1, 2012, and the
Administrator approves by October 1,
2012, such complete SIP revision, the
Administrator will record by October 1,
2012 in each TR NOX Annual source’s
compliance account the TR NOX Annual
allowances allocated to the TR NOX
Annual units at the source as provided
in such approved, complete SIP revision
for the control period in 2013.
(3) If the State submits to the
Administrator by April 1, 2012, and the
Administrator does not approve by
October 1, 2012, such complete SIP
revision, the Administrator will record
by October 1, 2012 in each TR NOX
Annual source’s compliance account the
TR NOX Annual allowances allocated to
the TR NOX Annual units at the source
in accordance with § 97.411(a) for the
control period in 2013.
(c) By July 1, 2013, the Administrator
will record in each TR NOX Annual
source’s compliance account the TR
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NOX Annual allowances allocated to the
TR NOX Annual units at the source, or
in each appropriate Allowance
Management System account the TR
NOX Annual allowances auctioned to
TR NOX Annual units, in accordance
with § 97.411(a), or with a SIP revision
approved under § 52.38(a)(4) or (5) of
this chapter, for the control period in
2014 and 2015.
(d) By July 1, 2014, the Administrator
will record in each TR NOX Annual
source’s compliance account the TR
NOX Annual allowances allocated to the
TR NOX Annual units at the source, or
in each appropriate Allowance
Management System account the TR
NOX Annual allowances auctioned to
TR NOX Annual units, in accordance
with § 97.411(a), or with a SIP revision
approved under § 52.38(a)(4) or (5) of
this chapter, for the control period in
2016 and 2017.
(e) By July 1, 2015, the Administrator
will record in each TR NOX Annual
source’s compliance account the TR
NOX Annual allowances allocated to the
TR NOX Annual units at the source, or
in each appropriate Allowance
Management System account the TR
NOX Annual allowances auctioned to
TR NOX Annual units, in accordance
with § 97.411(a), or with a SIP revision
approved under § 52.38(a)(4) or (5) of
this chapter, for the control period in
2018 and 2019.
(f) By July 1, 2016 and July 1 of each
year thereafter, the Administrator will
record in each TR NOX Annual source’s
compliance account the TR NOX Annual
allowances allocated to the TR NOX
Annual units at the source, or in each
appropriate Allowance Management
System account the TR NOX Annual
allowances auctioned to TR NOX
Annual units, in accordance with
§ 97.411(a), or with a SIP revision
approved under § 52.38(a)(4) or (5) of
this chapter, for the control period in
the fourth year after the year of the
applicable recordation deadline under
this paragraph.
(g) By August 1, 2012 and August 1
of each year thereafter, the
Administrator will record in each TR
NOX Annual source’s compliance
account the TR NOX Annual allowances
allocated to the TR NOX Annual units
at the source, or in each appropriate
Allowance Management System account
the TR NOX Annual allowances
auctioned to TR NOX Annual units, in
accordance with § 97.412(a)(2) through
(8) and (12), or with a SIP revision
approved under § 52.38(a)(4) or (5) of
this chapter, for the control period in
the year of the applicable recordation
deadline under this paragraph.
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(h) By August 1, 2012 and August 1
of each year thereafter, the
Administrator will record in each TR
NOX Annual source’s compliance
account the TR NOX Annual allowances
allocated to the TR NOX Annual units
at the source in accordance with
§ 97.412(b)(2) through (8) and (12) for
the control period in the year of the
applicable recordation deadline under
this paragraph.
(i) By February 15, 2013 and February
15 of each year thereafter, the
Administrator will record in each TR
NOX Annual source’s compliance
account the TR NOX Annual allowances
allocated to the TR NOX Annual units
at the source in accordance with
§ 97.412(a)(9) through (12), for the
control period in the year before the
year of the applicable recordation
deadline under this paragraph.
(j) By the date on which any
allocation or auction results, other than
an allocation or auction results
described in paragraphs (a) through (i)
of this section, of TR NOX Annual
allowances to a recipient is made by or
are submitted to the Administrator in
accordance with § 97.411 or § 97.412 or
with a SIP revision approved under
§ 52.38(a)(4) or (5) of this chapter, the
Administrator will record such
allocation or auction results in the
appropriate Allowance Management
System account.
(k) When recording the allocation or
auction of TR NOX Annual allowances
to a TR NOX Annual unit or other entity
in an Allowance Management System
account, the Administrator will assign
each TR NOX Annual allowance a
unique identification number that will
include digits identifying the year of the
control period for which the TR NOX
Annual allowance is allocated or
auctioned.
§ 97.422 Submission of TR NOX Annual
allowance transfers.
(a) An authorized account
representative seeking recordation of a
TR NOX Annual allowance transfer shall
submit the transfer to the Administrator.
(b) A TR NOX Annual allowance
transfer shall be correctly submitted if:
(1) The transfer includes the following
elements, in a format prescribed by the
Administrator:
(i) The account numbers established
by the Administrator for both the
transferor and transferee accounts;
(ii) The serial number of each TR NOX
Annual allowance that is in the
transferor account and is to be
transferred; and
(iii) The name and signature of the
authorized account representative of the
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48399
transferor account and the date signed;
and
(2) When the Administrator attempts
to record the transfer, the transferor
account includes each TR NOX Annual
allowance identified by serial number in
the transfer.
§ 97.423 Recordation of TR NOX Annual
allowance transfers.
(a) Within 5 business days (except as
provided in paragraph (b) of this
section) of receiving a TR NOX Annual
allowance transfer that is correctly
submitted under § 97.422, the
Administrator will record a TR NOX
Annual allowance transfer by moving
each TR NOX Annual allowance from
the transferor account to the transferee
account as specified in the transfer.
(b) A TR NOX Annual allowance
transfer to or from a compliance account
that is submitted for recordation after
the allowance transfer deadline for a
control period and that includes any TR
NOX Annual allowances allocated for
any control period before such
allowance transfer deadline will not be
recorded until after the Administrator
completes the deductions from such
compliance account under § 97.424 for
the control period immediately before
such allowance transfer deadline.
(c) Where a TR NOX Annual
allowance transfer is not correctly
submitted under § 97.422, the
Administrator will not record such
transfer.
(d) Within 5 business days of
recordation of a TR NOX Annual
allowance transfer under paragraphs (a)
and (b) of the section, the Administrator
will notify the authorized account
representatives of both the transferor
and transferee accounts.
(e) Within 10 business days of receipt
of a TR NOX Annual allowance transfer
that is not correctly submitted under
§ 97.422, the Administrator will notify
the authorized account representatives
of both accounts subject to the transfer
of:
(1) A decision not to record the
transfer, and
(2) The reasons for such nonrecordation.
§ 97.424 Compliance with TR NOX Annual
emissions limitation.
(a) Availability for deduction for
compliance. TR NOX Annual
allowances are available to be deducted
for compliance with a source’s TR NOX
Annual emissions limitation for a
control period in a given year only if the
TR NOX Annual allowances:
(1) Were allocated for such control
period or a control period in a prior
year; and
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(2) Are held in the source’s
compliance account as of the allowance
transfer deadline for such control
period.
(b) Deductions for compliance. After
the recordation, in accordance with
§ 97.423, of TR NOX Annual allowance
transfers submitted by the allowance
transfer deadline for a control period in
a given year, the Administrator will
deduct from each source’s compliance
account TR NOX Annual allowances
available under paragraph (a) of this
section in order to determine whether
the source meets the TR NOX Annual
emissions limitation for such control
period, as follows:
(1) Until the amount of TR NOX
Annual allowances deducted equals the
number of tons of total NOX emissions
from all TR NOX Annual units at the
source for such control period; or
(2) If there are insufficient TR NOX
Annual allowances to complete the
deductions in paragraph (b)(1) of this
section, until no more TR NOX Annual
allowances available under paragraph
(a) of this section remain in the
compliance account.
(c)(1) Identification of TR NOX
Annual allowances by serial number.
The authorized account representative
for a source’s compliance account may
request that specific TR NOX Annual
allowances, identified by serial number,
in the compliance account be deducted
for emissions or excess emissions for a
control period in a given year in
accordance with paragraph (b) or (d) of
this section. In order to be complete,
such request shall be submitted to the
Administrator by the allowance transfer
deadline for such control period and
include, in a format prescribed by the
Administrator, the identification of the
TR NOX Annual source and the
appropriate serial numbers.
(2) First-in, first-out. The
Administrator will deduct TR NOX
Annual allowances under paragraph (b)
or (d) of this section from the source’s
compliance account in accordance with
a complete request under paragraph
(c)(1) of this section or, in the absence
of such request or in the case of
identification of an insufficient amount
of TR NOX Annual allowances in such
request, on a first-in, first-out
accounting basis in the following order:
(i) Any TR NOX Annual allowances
that were allocated to the units at the
source and not transferred out of the
compliance account, in the order of
recordation; and then
(ii) Any TR NOX Annual allowances
that were allocated to any unit and
transferred to and recorded in the
compliance account pursuant to this
subpart, in the order of recordation.
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(d) Deductions for excess emissions.
After making the deductions for
compliance under paragraph (b) of this
section for a control period in a year in
which the TR NOX Annual source has
excess emissions, the Administrator will
deduct from the source’s compliance
account an amount of TR NOX Annual
allowances, allocated for a control
period in a prior year or the control
period in the year of the excess
emissions or in the immediately
following year, equal to two times the
number of tons of the source’s excess
emissions.
(e) Recordation of deductions. The
Administrator will record in the
appropriate compliance account all
deductions from such an account under
paragraphs (b) and (d) of this section.
§ 97.425 Compliance with TR NOX Annual
assurance provisions.
(a) Availability for deduction. TR NOX
Annual allowances are available to be
deducted for compliance with the TR
NOX Annual assurance provisions for a
control period in a given year by the
owners and operators of a group of one
or more TR NOX Annual sources and
units in a State (and Indian country
within the borders of such State) only if
the TR NOX Annual allowances:
(1) Were allocated for a control period
in a prior year or the control period in
the given year or in the immediately
following year; and
(2) Are held in the assurance account,
established by the Administrator for
such owners and operators of such
group of TR NOX Annual sources and
units in such State (and Indian country
within the borders of such State) under
paragraph (b)(3) of this section, as of the
deadline established in paragraph (b)(4)
of this section.
(b) Deductions for compliance. The
Administrator will deduct TR NOX
Annual allowances available under
paragraph (a) of this section for
compliance with the TR NOX Annual
assurance provisions for a State for a
control period in a given year in
accordance with the following
procedures:
(1) By June 1, 2013 and June 1 of each
year thereafter, the Administrator will:
(i) Calculate, for each State (and
Indian country within the borders of
such State), the total NOX emissions
from all TR NOX Annual units at TR
NOX Annual sources in the State (and
Indian country within the borders of
such State) during the control period in
the year before the year of this
calculation deadline and the amount, if
any, by which such total NOX emissions
exceed the State assurance level as
described in § 97.406(c)(2)(iii); and
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(ii) Promulgate a notice of data
availability of the results of the
calculations required in paragraph
(b)(1)(i) of this section, including
separate calculations of the NOX
emissions from each TR NOX Annual
source.
(2) For each notice of data availability
required in paragraph (b)(1)(ii) of this
section and for any State (and Indian
country within the borders of such
State) identified in such notice as
having TR NOX Annual units with total
NOX emissions exceeding the State
assurance level for a control period in
a given year, as described in
§ 97.406(c)(2)(iii):
(i) By July 1 immediately after the
promulgation of such notice, the
designated representative of each TR
NOX Annual source in each such State
(and Indian country within the borders
of such State) shall submit a statement,
in a format prescribed by the
Administrator, providing for each TR
NOX Annual unit (if any) at the source
that operates during, but is not allocated
an amount of TR NOX Annual
allowances for, such control period, the
unit’s allowable NOX emission rate for
such control period and, if such rate is
expressed in lb per mmBtu, the unit’s
heat rate.
(ii) By August 1 immediately after the
promulgation of such notice, the
Administrator will calculate, for each
such State (and Indian country within
the borders of such State) and such
control period and each common
designated representative for such
control period for a group of one or
more TR NOX Annual sources and units
in the State (and Indian country within
the borders of such State), the common
designated representative’s share of the
total NOX emissions from all TR NOX
Annual units at TR NOX Annual sources
in the State (and Indian country within
the borders of such State), the common
designated representative’s assurance
level, and the amount (if any) of TR
NOX Annual allowances that the owners
and operators of such group of sources
and units must hold in accordance with
the calculation formula in
§ 97.406(c)(2)(i) and will promulgate a
notice of data availability of the results
of these calculations.
(iii) The Administrator will provide
an opportunity for submission of
objections to the calculations referenced
by the notice of data availability
required in paragraph (b)(2)(ii) of this
section and the calculations referenced
by the relevant notice of data
availability required in paragraph
(b)(1)(i) of this section.
(A) Objections shall be submitted by
the deadline specified in such notice
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and shall be limited to addressing
whether the calculations referenced in
the relevant notice required under
paragraph (b)(1)(ii) of this section and
referenced in the notice required under
paragraph (b)(2)(ii) of this section are in
accordance with § 97.406(c)(2)(iii),
§§ 97.406(b) and 97.430 through 97.435,
the definitions of ‘‘common designated
representative’’, ‘‘common designated
representative’s assurance level’’, and
‘‘common designated representative’s
share’’ in § 97.402, and the calculation
formula in § 97.406(c)(2)(i).
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(2)(iii)(A) of this section. By October
1 immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of data availability
of any adjustments that the
Administrator determines to be
necessary and the reasons for accepting
or rejecting any objections submitted in
accordance with paragraph (b)(2)(iii)(A)
of this section.
(3) For any State (and Indian country
within the borders of such State)
referenced in each notice of data
availability required in paragraph
(b)(2)(iii)(B) of this section as having TR
NOX Annual units with total NOX
emissions exceeding the State assurance
level for a control period in a given year,
the Administrator will establish one
assurance account for each set of owners
and operators referenced, in the notice
of data availability required under
paragraph (b)(2)(iii)(B) of this section, as
all of the owners and operators of a
group of TR NOX Annual sources and
units in the State (and Indian country
within the borders of such State) having
a common designated representative for
such control period and as being
required to hold TR NOX Annual
allowances.
(4)(i) As of midnight of November 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(iii)(B) of this section,
the owners and operators described in
paragraph (b)(3) of this section shall
hold in the assurance account
established for the them and for the
appropriate TR NOX Annual sources, TR
NOX Annual units, and State (and
Indian country within the borders of
such State) under paragraph (b)(3) of
this section a total amount of TR NOX
Annual allowances, available for
deduction under paragraph (a) of this
section, equal to the amount such
owners and operators are required to
hold with regard to such sources, units
and State (and Indian country within
the borders of such State) as calculated
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by the Administrator and referenced in
such notice.
(ii) Notwithstanding the allowanceholding deadline specified in paragraph
(b)(4)(i) of this section, if November 1 is
not a business day, then such
allowance-holding deadline shall be
midnight of the first business day
thereafter.
(5) After November 1 (or the date
described in paragraph (b)(4)(ii) of this
section) immediately after the
promulgation of each notice of data
availability required in paragraph
(b)(2)(iii)(B) of this section and after the
recordation, in accordance with
§ 97.423, of TR NOX Annual allowance
transfers submitted by midnight of such
date, the Administrator will determine
whether the owners and operators
described in paragraph (b)(3) of this
section hold, in the assurance account
for the appropriate TR NOX Annual
sources, TR NOX Annual units, and
State (and Indian country within the
borders of such State) established under
paragraph (b)(3) of this section, the
amount of TR NOX Annual allowances
available under paragraph (a) of this
section that the owners and operators
are required to hold with regard to such
sources, units, and State (and Indian
country within the borders of such
State) as calculated by the
Administrator and referenced in the
notice required in paragraph
(b)(2)(iii)(B) of this section.
(6) Notwithstanding any other
provision of this subpart and any
revision, made by or submitted to the
Administrator after the promulgation of
the notice of data availability required
in paragraph (b)(2)(iii)(B) of this section
for a control period in a given year, of
any data used in making the
calculations referenced in such notice,
the amounts of TR NOX Annual
allowances that the owners and
operators are required to hold in
accordance with § 97.406(c)(2)(i) for
such control period shall continue to be
such amounts as calculated by the
Administrator and referenced in such
notice required in paragraph
(b)(2)(iii)(B) of this section, except as
follows:
(i) If any such data are revised by the
Administrator as a result of a decision
in or settlement of litigation concerning
such data on appeal under part 78 of
this chapter of such notice, or on appeal
under section 307 of the Clean Air Act
of a decision rendered under part 78 of
this chapter on appeal of such notice,
then the Administrator will use the data
as so revised to recalculate the amounts
of TR NOX Annual allowances that
owners and operators are required to
hold in accordance with the calculation
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48401
formula in § 97.406(c)(2)(i) for such
control period with regard to the TR
NOX Annual sources, TR NOX Annual
units, and State (and Indian country
within the borders of such State)
involved, provided that such litigation
under part 78 of this chapter, or the
proceeding under part 78 of this chapter
that resulted in the decision appealed in
such litigation under section 307 of the
Clean Air Act, was initiated no later
than 30 days after promulgation of such
notice required in paragraph
(b)(2)(iii)(B) of this section.
(ii) If any such data are revised by the
owners and operators of a TR NOX
Annual source and TR NOX Annual unit
whose designated representative
submitted such data under paragraph
(b)(2)(i) of this section, as a result of a
decision in or settlement of litigation
concerning such submission, then the
Administrator will use the data as so
revised to recalculate the amounts of TR
NOX Annual allowances that owners
and operators are required to hold in
accordance with the calculation formula
in § 97.406(c)(2)(i) for such control
period with regard to the TR NOX
Annual sources, TR NOX Annual units,
and State (and Indian country within
the borders of such State) involved,
provided that such litigation was
initiated no later than 30 days after
promulgation of such notice required in
paragraph (b)(2)(iii)(B) of this section.
(iii) If the revised data are used to
recalculate, in accordance with
paragraphs (b)(6)(i) and (ii) of this
section, the amount of TR NOX Annual
allowances that the owners and
operators are required to hold for such
control period with regard to the TR
NOX Annual sources, TR NOX Annual
units, and State (and Indian country
within the borders of such State)
involved—
(A) Where the amount of TR NOX
Annual allowances that the owners and
operators are required to hold increases
as a result of the use of all such revised
data, the Administrator will establish a
new, reasonable deadline on which the
owners and operators shall hold the
additional amount of TR NOX Annual
allowances in the assurance account
established by the Administrator for the
appropriate TR NOX Annual sources, TR
NOX Annual units, and State (and
Indian country within the borders of
such State) under paragraph (b)(3) of
this section. The owners’ and operators’
failure to hold such additional amount,
as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owners’ and operators’ failure
to hold such additional amount, as
required, as of the new deadline shall be
a violation of the Clean Air Act. Each
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TR NOX Annual allowance that the
owners and operators fail to hold as
required as of the new deadline, and
each day in such control period, shall be
a separate violation of the Clean Air Act.
(B) For the owners and operators for
which the amount of TR NOX Annual
allowances required to be held
decreases as a result of the use of all
such revised data, the Administrator
will record, in all accounts from which
TR NOX Annual allowances were
transferred by such owners and
operators for such control period to the
assurance account established by the
Administrator for the appropriate at TR
NOX Annual sources, TR NOX Annual
units, and State (and Indian country
within the borders of such State) under
paragraph (b)(3) of this section, a total
amount of the TR NOX Annual
allowances held in such assurance
account equal to the amount of the
decrease. If TR NOX Annual allowances
were transferred to such assurance
account from more than one account,
the amount of TR NOX Annual
allowances recorded in each such
transferor account will be in proportion
to the percentage of the total amount of
TR NOX Annual allowances transferred
to such assurance account for such
control period from such transferor
account.
(C) Each TR NOX Annual allowance
held under paragraph (b)(6)(iii)(A) of
this section as a result of recalculation
of requirements under the TR NOX
Annual assurance provisions for such
control period must be a TR NOX
Annual allowance allocated for a
control period in a year before or the
year immediately following, or in the
same year as, the year of such control
period.
§ 97.426
Banking.
(a) A TR NOX Annual allowance may
be banked for future use or transfer in
a compliance account or a general
account in accordance with paragraph
(b) of this section.
(b) Any TR NOX Annual allowance
that is held in a compliance account or
a general account will remain in such
account unless and until the TR NOX
Annual allowance is deducted or
transferred under § 97.411(c), § 97.423,
§ 97.424, § 97.425, 97.427, or 97.428.
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§ 97.427
Account error.
The Administrator may, at his or her
sole discretion and on his or her own
motion, correct any error in any
Allowance Management System
account. Within 10 business days of
making such correction, the
Administrator will notify the authorized
account representative for the account.
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§ 97.428 Administrator’s action on
submissions.
(a) The Administrator may review and
conduct independent audits concerning
any submission under the TR NOX
Annual Trading Program and make
appropriate adjustments of the
information in the submission.
(b) The Administrator may deduct TR
NOX Annual allowances from or transfer
TR NOX Annual allowances to a
compliance account or an assurance
account, based on the information in a
submission, as adjusted under
paragraph (a)(1) of this section, and
record such deductions and transfers.
§ 97.429
[Reserved]
§ 97.430 General monitoring,
recordkeeping, and reporting requirements.
The owners and operators, and to the
extent applicable, the designated
representative, of a TR NOX Annual
unit, shall comply with the monitoring,
recordkeeping, and reporting
requirements as provided in this subpart
and subpart H of part 75 of this chapter.
For purposes of applying such
requirements, the definitions in § 97.402
and in § 72.2 of this chapter shall apply,
the terms ‘‘affected unit,’’ ‘‘designated
representative,’’ and ‘‘continuous
emission monitoring system’’ (or
‘‘CEMS’’) in part 75 of this chapter shall
be deemed to refer to the terms ‘‘TR
NOX Annual unit,’’ ‘‘designated
representative,’’ and ‘‘continuous
emission monitoring system’’ (or
‘‘CEMS’’) respectively as defined in
§ 97.402, and the term ‘‘newly affected
unit’’ shall be deemed to mean ‘‘newly
affected TR NOX Annual unit’’. The
owner or operator of a unit that is not
a TR NOX Annual unit but that is
monitored under § 75.72(b)(2)(ii) of this
chapter shall comply with the same
monitoring, recordkeeping, and
reporting requirements as a TR NOX
Annual unit.
(a) Requirements for installation,
certification, and data accounting. The
owner or operator of each TR NOX
Annual unit shall:
(1) Install all monitoring systems
required under this subpart for
monitoring NOX mass emissions and
individual unit heat input (including all
systems required to monitor NOX
emission rate, NOX concentration, stack
gas moisture content, stack gas flow
rate, CO2 or O2 concentration, and fuel
flow rate, as applicable, in accordance
with §§ 75.71 and 75.72 of this chapter);
(2) Successfully complete all
certification tests required under
§ 97.431 and meet all other
requirements of this subpart and part 75
of this chapter applicable to the
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monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure
the data from the monitoring systems
under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as
provided in paragraph (e) of this
section, the owner or operator shall
meet the monitoring system certification
and other requirements of paragraphs
(a)(1) and (2) of this section on or before
the following dates and shall record,
report, and quality-assure the data from
the monitoring systems under paragraph
(a)(1) of this section on and after the
following dates.
(1) For the owner or operator of a TR
NOX Annual unit that commences
commercial operation before July 1,
2011, January 1, 2012;
(2) For the owner or operator of a TR
NOX Annual unit that commences
commercial operation on or after July 1,
2011, the later of the following:
(i) January 1, 2012; or
(ii) 180 calendar days after the date on
which the unit commences commercial
operation;
(3) The owner or operator of a TR
NOX Annual unit for which
construction of a new stack or flue or
installation of add-on NOX emission
controls is completed after the
applicable deadline under paragraph
(b)(1) or (2) of this section shall meet the
requirements of §§ 75.4(e)(1) through
(e)(4) of this chapter, except that:
(i) Such requirements shall apply to
the monitoring systems required under
§ 97.430 through § 97.435, rather than
the monitoring systems required under
part 75 of this chapter;
(ii) NOX emission rate, NOX
concentration, stack gas moisture
content, stack gas volumetric flow rate,
and O2 or CO2 concentration data shall
be determined and reported, rather than
the data listed in § 75.4(e)(2) of this
chapter; and
(iii) Any petition for another
procedure under § 75.4(e)(2) of this
chapter shall be submitted under
§ 97.435, rather than § 75.66.
(c) Reporting data. The owner or
operator of a TR NOX Annual unit that
does not meet the applicable
compliance date set forth in paragraph
(b) of this section for any monitoring
system under paragraph (a)(1) of this
section shall, for each such monitoring
system, determine, record, and report
maximum potential (or, as appropriate,
minimum potential) values for NOX
concentration, NOX emission rate, stack
gas flow rate, stack gas moisture
content, fuel flow rate, and any other
parameters required to determine NOX
mass emissions and heat input in
accordance with § 75.31(b)(2) or (c)(3) of
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this chapter, section 2.4 of appendix D
to part 75 of this chapter, or section 2.5
of appendix E to part 75 of this chapter,
as applicable.
(d) Prohibitions. (1) No owner or
operator of a TR NOX Annual unit shall
use any alternative monitoring system,
alternative reference method, or any
other alternative to any requirement of
this subpart without having obtained
prior written approval in accordance
with § 97.435.
(2) No owner or operator of a TR NOX
Annual unit shall operate the unit so as
to discharge, or allow to be discharged,
NOX to the atmosphere without
accounting for all such NOX in
accordance with the applicable
provisions of this subpart and part 75 of
this chapter.
(3) No owner or operator of a TR NOX
Annual unit shall disrupt the
continuous emission monitoring system,
any portion thereof, or any other
approved emission monitoring method,
and thereby avoid monitoring and
recording NOX mass discharged into the
atmosphere or heat input, except for
periods of recertification or periods
when calibration, quality assurance
testing, or maintenance is performed in
accordance with the applicable
provisions of this subpart and part 75 of
this chapter.
(4) No owner or operator of a TR NOX
Annual unit shall retire or permanently
discontinue use of the continuous
emission monitoring system, any
component thereof, or any other
approved monitoring system under this
subpart, except under any one of the
following circumstances:
(i) During the period that the unit is
covered by an exemption under § 97.405
that is in effect;
(ii) The owner or operator is
monitoring emissions from the unit with
another certified monitoring system
approved, in accordance with the
applicable provisions of this subpart
and part 75 of this chapter, by the
Administrator for use at that unit that
provides emission data for the same
pollutant or parameter as the retired or
discontinued monitoring system; or
(iii) The designated representative
submits notification of the date of
certification testing of a replacement
monitoring system for the retired or
discontinued monitoring system in
accordance with § 97.431(d)(3)(i).
(e) Long-term cold storage. The owner
or operator of a TR NOX Annual unit is
subject to the applicable provisions of
§ 75.4(d) of this chapter concerning
units in long-term cold storage.
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§ 97.431 Initial monitoring system
certification and recertification procedures.
(a) The owner or operator of a TR NOX
Annual unit shall be exempt from the
initial certification requirements of this
section for a monitoring system under
§ 97.430(a)(1) if the following conditions
are met:
(1) The monitoring system has been
previously certified in accordance with
part 75 of this chapter; and
(2) The applicable quality-assurance
and quality-control requirements of
§ 75.21 of this chapter and appendices
B, D, and E to part 75 of this chapter are
fully met for the certified monitoring
system described in paragraph (a)(1) of
this section.
(b) The recertification provisions of
this section shall apply to a monitoring
system under § 97.430(a)(1) that is
exempt from initial certification
requirements under paragraph (a) of this
section.
(c) If the Administrator has previously
approved a petition under § 75.17(a) or
(b) of this chapter for apportioning the
NOX emission rate measured in a
common stack or a petition under
§ 75.66 of this chapter for an alternative
to a requirement in § 75.12 or § 75.17 of
this chapter, the designated
representative shall resubmit the
petition to the Administrator under
§ 97.435 to determine whether the
approval applies under the TR NOX
Annual Trading Program.
(d) Except as provided in paragraph
(a) of this section, the owner or operator
of a TR NOX Annual unit shall comply
with the following initial certification
and recertification procedures for a
continuous monitoring system (i.e., a
continuous emission monitoring system
and an excepted monitoring system
under appendices D and E to part 75 of
this chapter) under § 97.430(a)(1). The
owner or operator of a unit that qualifies
to use the low mass emissions excepted
monitoring methodology under § 75.19
of this chapter or that qualifies to use an
alternative monitoring system under
subpart E of part 75 of this chapter shall
comply with the procedures in
paragraph (e) or (f) of this section
respectively.
(1) Requirements for initial
certification. The owner or operator
shall ensure that each continuous
monitoring system under § 97.430(a)(1)
(including the automated data
acquisition and handling system)
successfully completes all of the initial
certification testing required under
§ 75.20 of this chapter by the applicable
deadline in § 97.430(b). In addition,
whenever the owner or operator installs
a monitoring system to meet the
requirements of this subpart in a
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48403
location where no such monitoring
system was previously installed, initial
certification in accordance with § 75.20
of this chapter is required.
(2) Requirements for recertification.
Whenever the owner or operator makes
a replacement, modification, or change
in any certified continuous emission
monitoring system under § 97.430(a)(1)
that may significantly affect the ability
of the system to accurately measure or
record NOX mass emissions or heat
input rate or to meet the qualityassurance and quality-control
requirements of § 75.21 of this chapter
or appendix B to part 75 of this chapter,
the owner or operator shall recertify the
monitoring system in accordance with
§ 75.20(b) of this chapter. Furthermore,
whenever the owner or operator makes
a replacement, modification, or change
to the flue gas handling system or the
unit’s operation that may significantly
change the stack flow or concentration
profile, the owner or operator shall
recertify each continuous emission
monitoring system whose accuracy is
potentially affected by the change, in
accordance with § 75.20(b) of this
chapter. Examples of changes to a
continuous emission monitoring system
that require recertification include
replacement of the analyzer, complete
replacement of an existing continuous
emission monitoring system, or change
in location or orientation of the
sampling probe or site. Any fuel
flowmeter system, and any excepted
NOX monitoring system under appendix
E to part 75 of this chapter, under
§ 97.430(a)(1) are subject to the
recertification requirements in
§ 75.20(g)(6) of this chapter.
(3) Approval process for initial
certification and recertification. For
initial certification of a continuous
monitoring system under § 97.430(a)(1),
paragraphs (d)(3)(i) through (v) of this
section apply. For recertifications of
such monitoring systems, paragraphs
(d)(3)(i) through (iv) of this section and
the procedures in §§ 75.20(b)(5) and
(g)(7) of this chapter (in lieu of the
procedures in paragraph (d)(3)(v) of this
section) apply, provided that in
applying paragraphs (d)(3)(i) through
(iv) of this section, the words
‘‘certification’’ and ‘‘initial certification’’
are replaced by the word
‘‘recertification’’ and the word
‘‘certified’’ is replaced by with the word
‘‘recertified’’.
(i) Notification of certification. The
designated representative shall submit
to the appropriate EPA Regional Office
and the Administrator written notice of
the dates of certification testing, in
accordance with § 97.433.
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(ii) Certification application. The
designated representative shall submit
to the Administrator a certification
application for each monitoring system.
A complete certification application
shall include the information specified
in § 75.63 of this chapter.
(iii) Provisional certification date. The
provisional certification date for a
monitoring system shall be determined
in accordance with § 75.20(a)(3) of this
chapter. A provisionally certified
monitoring system may be used under
the TR NOX Annual Trading Program
for a period not to exceed 120 days after
receipt by the Administrator of the
complete certification application for
the monitoring system under paragraph
(d)(3)(ii) of this section. Data measured
and recorded by the provisionally
certified monitoring system, in
accordance with the requirements of
part 75 of this chapter, will be
considered valid quality-assured data
(retroactive to the date and time of
provisional certification), provided that
the Administrator does not invalidate
the provisional certification by issuing a
notice of disapproval within 120 days of
the date of receipt of the complete
certification application by the
Administrator.
(iv) Certification application approval
process. The Administrator will issue a
written notice of approval or
disapproval of the certification
application to the owner or operator
within 120 days of receipt of the
complete certification application under
paragraph (d)(3)(ii) of this section. In the
event the Administrator does not issue
such a notice within such 120-day
period, each monitoring system that
meets the applicable performance
requirements of part 75 of this chapter
and is included in the certification
application will be deemed certified for
use under the TR NOX Annual Trading
Program.
(A) Approval notice. If the
certification application is complete and
shows that each monitoring system
meets the applicable performance
requirements of part 75 of this chapter,
then the Administrator will issue a
written notice of approval of the
certification application within 120
days of receipt.
(B) Incomplete application notice. If
the certification application is not
complete, then the Administrator will
issue a written notice of incompleteness
that sets a reasonable date by which the
designated representative must submit
the additional information required to
complete the certification application. If
the designated representative does not
comply with the notice of
incompleteness by the specified date,
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then the Administrator may issue a
notice of disapproval under paragraph
(d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the
certification application shows that any
monitoring system does not meet the
performance requirements of part 75 of
this chapter or if the certification
application is incomplete and the
requirement for disapproval under
paragraph (d)(3)(iv)(B) of this section is
met, then the Administrator will issue a
written notice of disapproval of the
certification application. Upon issuance
of such notice of disapproval, the
provisional certification is invalidated
by the Administrator and the data
measured and recorded by each
uncertified monitoring system shall not
be considered valid quality-assured data
beginning with the date and hour of
provisional certification (as defined
under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The
Administrator may issue a notice of
disapproval of the certification status of
a monitor in accordance with
§ 97.432(b).
(v) Procedures for loss of certification.
If the Administrator issues a notice of
disapproval of a certification
application under paragraph
(d)(3)(iv)(C) of this section or a notice of
disapproval of certification status under
paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall
substitute the following values, for each
disapproved monitoring system, for
each hour of unit operation during the
period of invalid data specified under
§ 75.20(a)(4)(iii), § 75.20(g)(7), or
§ 75.21(e) of this chapter and continuing
until the applicable date and hour
specified under § 75.20(a)(5)(i) or (g)(7)
of this chapter:
(1) For a disapproved NOX emission
rate (i.e., NOX-diluent) system, the
maximum potential NOX emission rate,
as defined in § 72.2 of this chapter.
(2) For a disapproved NOX pollutant
concentration monitor and disapproved
flow monitor, respectively, the
maximum potential concentration of
NOX and the maximum potential flow
rate, as defined in sections 2.1.2.1 and
2.1.4.1 of appendix A to part 75 of this
chapter.
(3) For a disapproved moisture
monitoring system and disapproved
diluent gas monitoring system,
respectively, the minimum potential
moisture percentage and either the
maximum potential CO2 concentration
or the minimum potential O2
concentration (as applicable), as defined
in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
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(4) For a disapproved fuel flowmeter
system, the maximum potential fuel
flow rate, as defined in section 2.4.2.1
of appendix D to part 75 of this chapter.
(5) For a disapproved excepted NOX
monitoring system under appendix E to
part 75 of this chapter, the fuel-specific
maximum potential NOX emission rate,
as defined in § 72.2 of this chapter.
(B) The designated representative
shall submit a notification of
certification retest dates and a new
certification application in accordance
with paragraphs (d)(3)(i) and (ii) of this
section.
(C) The owner or operator shall repeat
all certification tests or other
requirements that were failed by the
monitoring system, as indicated in the
Administrator’s notice of disapproval,
no later than 30 unit operating days
after the date of issuance of the notice
of disapproval.
(e) The owner or operator of a unit
qualified to use the low mass emissions
(LME) excepted methodology under
§ 75.19 of this chapter shall meet the
applicable certification and
recertification requirements in
§§ 75.19(a)(2) and 75.20(h) of this
chapter. If the owner or operator of such
a unit elects to certify a fuel flowmeter
system for heat input determination, the
owner or operator shall also meet the
certification and recertification
requirements in § 75.20(g) of this
chapter.
(f) The designated representative of
each unit for which the owner or
operator intends to use an alternative
monitoring system approved by the
Administrator under subpart E of part
75 of this chapter shall comply with the
applicable notification and application
procedures of § 75.20(f) of this chapter.
§ 97.432 Monitoring system out-of-control
periods.
(a) General provisions. Whenever any
monitoring system fails to meet the
quality-assurance and quality-control
requirements or data validation
requirements of part 75 of this chapter,
data shall be substituted using the
applicable missing data procedures in
subpart D or subpart H of, or appendix
D or appendix E to, part 75 of this
chapter.
(b) Audit decertification. Whenever
both an audit of a monitoring system
and a review of the initial certification
or recertification application reveal that
any monitoring system should not have
been certified or recertified because it
did not meet a particular performance
specification or other requirement under
§ 97.431 or the applicable provisions of
part 75 of this chapter, both at the time
of the initial certification or
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recertification application submission
and at the time of the audit, the
Administrator will issue a notice of
disapproval of the certification status of
such monitoring system. For the
purposes of this paragraph, an audit
shall be either a field audit or an audit
of any information submitted to the
Administrator or any State or permitting
authority. By issuing the notice of
disapproval, the Administrator revokes
prospectively the certification status of
the monitoring system. The data
measured and recorded by the
monitoring system shall not be
considered valid quality-assured data
from the date of issuance of the
notification of the revoked certification
status until the date and time that the
owner or operator completes
subsequently approved initial
certification or recertification tests for
the monitoring system. The owner or
operator shall follow the applicable
initial certification or recertification
procedures in § 97.431 for each
disapproved monitoring system.
§ 97.433 Notifications concerning
monitoring.
The designated representative of a TR
NOX Annual unit shall submit written
notice to the Administrator in
accordance with § 75.61 of this chapter.
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§ 97.434
Recordkeeping and reporting.
(a) General provisions. The designated
representative shall comply with all
recordkeeping and reporting
requirements in paragraphs (b) through
(e) of this section, the applicable
recordkeeping and reporting
requirements under § 75.73 of this
chapter, and the requirements of
§ 97.414(a).
(b) Monitoring plans. The owner or
operator of a TR NOX Annual unit shall
comply with requirements of § 75.73(c)
and (e) of this chapter.
(c) Certification applications. The
designated representative shall submit
an application to the Administrator
within 45 days after completing all
initial certification or recertification
tests required under § 97.431, including
the information required under § 75.63
of this chapter.
(d) Quarterly reports. The designated
representative shall submit quarterly
reports, as follows:
(1) The designated representative
shall report the NOX mass emissions
data and heat input data for the TR NOX
Annual unit, in an electronic quarterly
report in a format prescribed by the
Administrator, for each calendar quarter
beginning with:
(i) For a unit that commences
commercial operation before July 1,
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2011, the calendar quarter covering
January 1, 2012 through March 31, 2012;
or
(ii) For a unit that commences
commercial operation on or after July 1,
2011, the calendar quarter
corresponding to the earlier of the date
of provisional certification or the
applicable deadline for initial
certification under § 97.430(b), unless
that quarter is the third or fourth quarter
of 2011, in which case reporting shall
commence in the quarter covering
January 1, 2012 through March 31, 2012.
(2) The designated representative
shall submit each quarterly report to the
Administrator within 30 days after the
end of the calendar quarter covered by
the report. Quarterly reports shall be
submitted in the manner specified in
§ 75.73(f) of this chapter.
(3) For TR NOX Annual units that are
also subject to the Acid Rain Program,
TR NOX Ozone Season Trading
Program, TR SO2 Group 1 Trading
Program, or TR SO2 Group 2 Trading
Program, quarterly reports shall include
the applicable data and information
required by subparts F through H of part
75 of this chapter as applicable, in
addition to the NOX mass emission data,
heat input data, and other information
required by this subpart.
(4) The Administrator may review and
conduct independent audits of any
quarterly report in order to determine
whether the quarterly report meets the
requirements of this subpart and part 75
of this chapter, including the
requirement to use substitute data.
(i) The Administrator will notify the
designated representative of any
determination that the quarterly report
fails to meet any such requirements and
specify in such notification any
corrections that the Administrator
believes are necessary to make through
resubmission of the quarterly report and
a reasonable time period within which
the designated representative must
respond. Upon request by the
designated representative, the
Administrator may specify reasonable
extensions of such time period. Within
the time period (including any such
extensions) specified by the
Administrator, the designated
representative shall resubmit the
quarterly report with the corrections
specified by the Administrator, except
to the extent the designated
representative provides information
demonstrating that a specified
correction is not necessary because the
quarterly report already meets the
requirements of this subpart and part 75
of this chapter that are relevant to the
specified correction.
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(ii) Any resubmission of a quarterly
report shall meet the requirements
applicable to the submission of a
quarterly report under this subpart and
part 75 of this chapter, except for the
deadline set forth in paragraph (d)(2) of
this section.
(e) Compliance certification. The
designated representative shall submit
to the Administrator a compliance
certification (in a format prescribed by
the Administrator) in support of each
quarterly report based on reasonable
inquiry of those persons with primary
responsibility for ensuring that all of the
unit’s emissions are correctly and fully
monitored. The certification shall state
that:
(1) The monitoring data submitted
were recorded in accordance with the
applicable requirements of this subpart
and part 75 of this chapter, including
the quality assurance procedures and
specifications; and
(2) For a unit with add-on NOX
emission controls and for all hours
where NOX data are substituted in
accordance with § 75.34(a)(1) of this
chapter, the add-on emission controls
were operating within the range of
parameters listed in the quality
assurance/quality control program
under appendix B to part 75 of this
chapter and the substitute data values
do not systematically underestimate
NOX emissions.
§ 97.435 Petitions for alternatives to
monitoring, recordkeeping, or reporting
requirements.
(a) The designated representative of a
TR NOX Annual unit may submit a
petition under § 75.66 of this chapter to
the Administrator, requesting approval
to apply an alternative to any
requirement of §§ 97.430 through
97.434.
(b) A petition submitted under
paragraph (a) of this section shall
include sufficient information for the
evaluation of the petition, including, at
a minimum, the following information:
(i) Identification of each unit and
source covered by the petition;
(ii) A detailed explanation of why the
proposed alternative is being suggested
in lieu of the requirement;
(iii) A description and diagram of any
equipment and procedures used in the
proposed alternative;
(iv) A demonstration that the
proposed alternative is consistent with
the purposes of the requirement for
which the alternative is proposed and
with the purposes of this subpart and
part 75 of this chapter and that any
adverse effect of approving the
alternative will be de minimis; and
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(v) Any other relevant information
that the Administrator may require.
(c) Use of an alternative to any
requirement referenced in paragraph (a)
of this section is in accordance with this
subpart only to the extent that the
petition is approved in writing by the
Administrator and that such use is in
accordance with such approval.
■ 75. Part 97 is amended by adding
subpart BBBBB to read as follows:
Subpart BBBBB—TR NOX Ozone Season
Trading Program
97.501 Purpose.
97.502 Definitions.
97.503 Measurements, abbreviations, and
acronyms.
97.504 Applicability.
97.505 Retired unit exemption.
97.506 Standard requirements.
97.507 Computation of time.
97.508 Administrative appeal procedures.
97.509 [Reserved]
97.510 State NOX Ozone Season trading
budgets, new unit set-asides, Indian
country new unit set-asides and
variability limits.
97.511 Timing requirements for TR NOX
Ozone Season allowance allocations.
97.512 TR NOX Ozone Season allowance
allocations to new units.
97.513 Authorization of designated
representative and alternate designated
representative.
97.514 Responsibilities of designated
representative and alternate designated
representative.
97.515 Changing designated representative
and alternate designated representative;
changes in owners and operators.
97.516 Certificate of representation.
97.517 Objections concerning designated
representative and alternate designated
representative.
97.518 Delegation by designated
representative and alternate designated
representative.
97.519 [Reserved]
97.520 Establishment of compliance
accounts and general accounts.
97.521 Recordation of TR NOX Ozone
Season allowance allocations.
97.522 Submission of TR NOX Ozone
Season allowance transfers.
97.523 Recordation of TR NOX Ozone
Season allowance transfers.
97.524 Compliance with TR NOX Ozone
Season emissions limitation.
97.525 Compliance with TR NOX Ozone
Season assurance provisions.
97.526 Banking.
97.527 Account error.
97.528 Administrator’s action on
submissions.
97.529 [RESERVED]
97.530 General monitoring, recordkeeping,
and reporting requirements.
97.531 Initial monitoring system
certification and recertification
procedures.
97.532 Monitoring system out-of-control
periods.
97.533 Notifications concerning
monitoring.
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97.534 Recordkeeping and reporting.
97.535 Petitions for alternatives to
monitoring, recordkeeping, or reporting
requirements.
Subpart BBBBB—TR NOX Ozone
Season Trading Program
§ 97.501
Purpose.
This subpart sets forth the general,
designated representative, allowance,
and monitoring provisions for the
Transport Rule (TR) NOX Ozone Season
Trading Program, under section 110 of
the Clean Air Act and § 52.38 of this
chapter, as a means of mitigating
interstate transport of ozone and
nitrogen oxides.
§ 97.502
Definitions.
The terms used in this subpart shall
have the meanings set forth in this
section as follows:
Acid Rain Program means a multistate SO2 and NOX air pollution control
and emission reduction program
established by the Administrator under
title IV of the Clean Air Act and parts
72 through 78 of this chapter.
Administrator means the
Administrator of the United States
Environmental Protection Agency or the
Director of the Clean Air Markets
Division (or its successor determined by
the Administrator) of the United States
Environmental Protection Agency, the
Administrator’s duly authorized
representative under this subpart.
Allocate or allocation means, with
regard to TR NOX Ozone Season
allowances, the determination by the
Administrator, State, or permitting
authority, in accordance with this
subpart and any SIP revision submitted
by the State and approved by the
Administrator under § 52.38(b)(3), (4),
or (5) of this chapter, of the amount of
such TR NOX Ozone Season allowances
to be initially credited, at no cost to the
recipient, to:
(1) A TR NOX Ozone Season unit;
(2) A new unit set-aside;
(3) An Indian country new unit setaside; or
(4) An entity not listed in paragraphs
(1) through (3) of this definition;
(5) Provided that, if the
Administrator, State, or permitting
authority initially credits, to a TR NOX
Ozone Season unit qualifying for an
initial credit, a credit in the amount of
zero TR NOX Ozone Season allowances,
the TR NOX Ozone Season unit will be
treated as being allocated an amount
(i.e., zero) of TR NOX Ozone Season
allowances.
Allowable NOX emission rate means,
for a unit, the most stringent State or
federal NOX emission rate limit (in
lb/MWhr or, if in lb/mmBtu, converted
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to lb/MWhr by multiplying it by the
unit’s heat rate in mmBtu/MWhr) that is
applicable to the unit and covers the
longest averaging period not exceeding
one year.
Allowance Management System
means the system by which the
Administrator records allocations,
deductions, and transfers of TR NOX
Ozone Season allowances under the TR
NOX Ozone Season Trading Program.
Such allowances are allocated,
recorded, held, deducted, or transferred
only as whole allowances.
Allowance Management System
account means an account in the
Allowance Management System
established by the Administrator for
purposes of recording the allocation,
holding, transfer, or deduction of TR
NOX Ozone Season allowances.
Allowance transfer deadline means,
for a control period in a given year,
midnight of December 1 (if it is a
business day), or midnight of the first
business day thereafter (if December 1 is
not a business day), immediately after
such control period and is the deadline
by which a TR NOX Ozone Season
allowance transfer must be submitted
for recordation in a TR NOX Ozone
Season source’s compliance account in
order to be available for use in
complying with the source’s TR NOX
Ozone Season emissions limitation for
such control period in accordance with
§§ 97.506 and 97.524.
Alternate designated representative
means, for a TR NOX Ozone Season
source and each TR NOX Ozone Season
unit at the source, the natural person
who is authorized by the owners and
operators of the source and all such
units at the source, in accordance with
this subpart, to act on behalf of the
designated representative in matters
pertaining to the TR NOX Ozone Season
Trading Program. If the TR NOX Ozone
Season source is also subject to the Acid
Rain Program, TR NOX Annual Trading
Program, TR SO2 Group 1 Trading
Program, or TR SO2 Group 2 Trading
Program, then this natural person shall
be the same natural person as the
alternate designated representative, as
defined in the respective program.
Assurance account means an
Allowance Management System
account, established by the
Administrator under § 97.525(b)(3) for
certain owners and operators of a group
of one or more TR NOX Ozone Season
sources and units in a given State (and
Indian country within the borders of
such State), in which are held TR NOX
Ozone Season allowances available for
use for a control period in a given year
in complying with the TR NOX Ozone
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Season assurance provisions in
accordance with §§ 97.506 and 97.525.
Authorized account representative
means, for a general account, the natural
person who is authorized, in accordance
with this subpart, to transfer and
otherwise dispose of TR NOX Ozone
Season allowances held in the general
account and, for a TR NOX Ozone
Season source’s compliance account,
the designated representative of the
source.
Automated data acquisition and
handling system or DAHS means the
component of the continuous emission
monitoring system, or other emissions
monitoring system approved for use
under this subpart, designed to interpret
and convert individual output signals
from pollutant concentration monitors,
flow monitors, diluent gas monitors,
and other component parts of the
monitoring system to produce a
continuous record of the measured
parameters in the measurement units
required by this subpart.
Biomass means—
(1) Any organic material grown for the
purpose of being converted to energy;
(2) Any organic byproduct of
agriculture that can be converted into
energy; or
(3) Any material that can be converted
into energy and is nonmerchantable for
other purposes, that is segregated from
other material that is nonmerchantable
for other purposes, and that is;
(i) A forest-related organic resource,
including mill residues, precommercial
thinnings, slash, brush, or byproduct
from conversion of trees to
merchantable material; or
(ii) A wood material, including
pallets, crates, dunnage, manufacturing
and construction materials (other than
pressure-treated, chemically-treated, or
painted wood products), and landscape
or right-of-way tree trimmings.
Boiler means an enclosed fossil- or
other-fuel-fired combustion device used
to produce heat and to transfer heat to
recirculating water, steam, or other
medium.
Bottoming-cycle unit means a unit in
which the energy input to the unit is
first used to produce useful thermal
energy, where at least some of the reject
heat from the useful thermal energy
application or process is then used for
electricity production.
Business day means a day that does
not fall on a weekend or a federal
holiday.
Certifying official means a natural
person who is:
(1) For a corporation, a president,
secretary, treasurer, or vice-president of
the corporation in charge of a principal
business function or any other person
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who performs similar policy- or
decision-making functions for the
corporation;
(2) For a partnership or sole
proprietorship, a general partner or the
proprietor respectively; or
(3) For a local government entity or
State, federal, or other public agency, a
principal executive officer or ranking
elected official.
Clean Air Act means the Clean Air
Act, 42 U.S.C. 7401, et seq.
Coal means ‘‘coal’’ as defined in
§ 72.2 of this chapter.
Coal-derived fuel means any fuel
(whether in a solid, liquid, or gaseous
state) produced by the mechanical,
thermal, or chemical processing of coal.
Cogeneration system means an
integrated group, at a source, of
equipment (including a boiler, or
combustion turbine, and a steam turbine
generator) designed to produce useful
thermal energy for industrial,
commercial, heating, or cooling
purposes and electricity through the
sequential use of energy.
Cogeneration unit means a stationary,
fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine that
is a topping-cycle unit or a bottomingcycle unit:
(1) Operating as part of a cogeneration
system; and
(2) Producing on an annual average
basis—
(i) For a topping-cycle unit,
(A) Useful thermal energy not less
than 5 percent of total energy output;
and
(B) Useful power that, when added to
one-half of useful thermal energy
produced, is not less than 42.5 percent
of total energy input, if useful thermal
energy produced is 15 percent or more
of total energy output, or not less than
45 percent of total energy input, if
useful thermal energy produced is less
than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful
power not less than 45 percent of total
energy input;
(3) Provided that the requirements in
paragraph (2) of this definition shall not
apply to a calendar year referenced in
paragraph (2) of this definition during
which the unit did not operate at all;
(4) Provided that the total energy
input under paragraphs (2)(i)(B) and
(2)(ii) of this definition shall equal the
unit’s total energy input from all fuel,
except biomass if the unit is a boiler;
and
(5) Provided that, if, throughout its
operation during the 12-month period or
a calendar year referenced in paragraph
(2) of this definition, a unit is operated
as part of a cogeneration system and the
cogeneration system meets on a system-
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48407
wide basis the requirement in paragraph
(2)(i)(B) or (2)(ii) of this definition, the
unit shall be deemed to meet such
requirement during that 12-month
period or calendar year.
Combustion turbine means an
enclosed device comprising:
(1) If the device is simple cycle, a
compressor, a combustor, and a turbine
and in which the flue gas resulting from
the combustion of fuel in the combustor
passes through the turbine, rotating the
turbine; and
(2) If the device is combined cycle,
the equipment described in paragraph
(1) of this definition and any associated
duct burner, heat recovery steam
generator, and steam turbine.
Commence commercial operation
means, with regard to a unit:
(1) To have begun to produce steam,
gas, or other heated medium used to
generate electricity for sale or use,
including test generation, except as
provided in § 97.505.
(i) For a unit that is a TR NOX Ozone
Season unit under § 97.504 on the later
of January 1, 2005 or the date the unit
commences commercial operation as
defined in the introductory text of
paragraph (1) of this definition and that
subsequently undergoes a physical
change or is moved to a new location or
source, such date shall remain the date
of commencement of commercial
operation of the unit, which shall
continue to be treated as the same unit.
(ii) For a unit that is a TR NOX Ozone
Season unit under § 97.504 on the later
of January 1, 2005 or the date the unit
commences commercial operation as
defined in the introductory text of
paragraph (1) of this definition and that
is subsequently replaced by a unit at the
same or a different source, such date
shall remain the replaced unit’s date of
commencement of commercial
operation, and the replacement unit
shall be treated as a separate unit with
a separate date for commencement of
commercial operation as defined in
paragraph (1) or (2) of this definition as
appropriate.
(2) Notwithstanding paragraph (1) of
this definition and except as provided
in § 97.505, for a unit that is not a TR
NOX Ozone Season unit under § 97.504
on the later of January 1, 2005 or the
date the unit commences commercial
operation as defined in introductory text
of paragraph (1) of this definition, the
unit’s date for commencement of
commercial operation shall be the date
on which the unit becomes a TR NOX
Ozone Season unit under § 97.504.
(i) For a unit with a date for
commencement of commercial
operation as defined in the introductory
text of paragraph (2) of this definition
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and that subsequently undergoes a
physical change or is moved to a
different location or source, such date
shall remain the date of commencement
of commercial operation of the unit,
which shall continue to be treated as the
same unit.
(ii) For a unit with a date for
commencement of commercial
operation as defined in the introductory
text of paragraph (2) of this definition
and that is subsequently replaced by a
unit at the same or a different source,
such date shall remain the replaced
unit’s date of commencement of
commercial operation, and the
replacement unit shall be treated as a
separate unit with a separate date for
commencement of commercial
operation as defined in paragraph (1) or
(2) of this definition as appropriate.
Common designated representative
means, with regard to a control period
in a given year, a designated
representative where, as of April 1
immediately after the allowance transfer
deadline for such control period, the
same natural person is authorized under
§§ 97.513(a) and 97.515(a) as the
designated representative for a group of
one or more TR NOX Ozone Season
sources and units located in a State (and
Indian country within the borders of
such State).
Common designated representative’s
assurance level means, with regard to a
specific common designated
representative and a State (and Indian
country within the borders of such
State) and control period in a given year
for which the State assurance level is
exceeded as described in
§ 97.506(c)(2)(iii), the common
designated representative’s share of the
State NOX Ozone Season trading budget
with the variability limit for the State
for such control period.
Common designated representative’s
share means, with regard to a specific
common designated representative for a
control period in a given year:
(1) With regard to a total amount of
NOX emissions from all TR NOX Ozone
Season units in a State (and Indian
country within the borders of such
State) during such control period, the
total tonnage of NOX emissions during
such control period from a group of one
or more TR NOX Ozone Season units
located in such State (and such Indian
country) and having the common
designated representative for such
control period;
(2) With regard to a State NOX Ozone
Season trading budget with the
variability limit for such control period,
the amount (rounded to the nearest
allowance) equal to the sum of the total
amount of TR NOX Ozone Season
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allowances allocated for such control
period to a group of one or more TR
NOX Ozone Season units located in the
State (and Indian country within the
borders of such State) and having the
common designated representative for
such control period and of the total
amount of TR NOX Ozone Season
allowances purchased by an owner or
operator of such TR NOX Ozone Season
units in an auction for such control
period and submitted by the State or the
permitting authority to the
Administrator for recordation in the
compliance accounts for such TR NOX
Ozone Season units in accordance with
the TR NOX Ozone Season allowance
auction provisions in a SIP revision
approved by the Administrator under
§ 52.38(b)(4) or (5) of this chapter,
multiplied by the sum of the State NOX
Ozone Season trading budget under
§ 97.510(a) and the State’s variability
limit under § 97.510(b) for such control
period and divided by such State NOX
Ozone Season trading budget;
(3) Provided that, in the case of a unit
that operates during, but has no amount
of TR NOX Ozone Season allowances
allocated under §§ 97.511 and 97.512
for, such control period, the unit shall
be treated, solely for purposes of this
definition, as being allocated an amount
(rounded to the nearest allowance) of
TR NOX Ozone Season allowances for
such control period equal to the unit’s
allowable NOX emission rate applicable
to such control period, multiplied by a
capacity factor of 0.92 (if the unit is a
boiler combusting any amount of coal or
coal-derived fuel during such control
period), 0.32 (if the unit is a simple
combustion turbine during such control
period), 0.71 (if the unit is a combined
cycle turbine during such control
period), 0.73 (if the unit is an integrated
coal gasification combined cycle unit
during such control period), or 0.44 (for
any other unit), multiplied by the unit’s
maximum hourly load as reported in
accordance with this subpart and by
3,672 hours/control period, and divided
by 2,000 lb/ton.
Common stack means a single flue
through which emissions from 2 or
more units are exhausted.
Compliance account means an
Allowance Management System
account, established by the
Administrator for a TR NOX Ozone
Season source under this subpart, in
which any TR NOX Ozone Season
allowance allocations to the TR NOX
Ozone Season units at the source are
recorded and in which are held any TR
NOX Ozone Season allowances available
for use for a control period in a given
year in complying with the source’s TR
NOX Ozone Season emissions limitation
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in accordance with §§ 97.506 and
97.524.
Continuous emission monitoring
system or CEMS means the equipment
required under this subpart to sample,
analyze, measure, and provide, by
means of readings recorded at least once
every 15 minutes and using an
automated data acquisition and
handling system (DAHS), a permanent
record of NOX emissions, stack gas
volumetric flow rate, stack gas moisture
content, and O2 or CO2 concentration (as
applicable), in a manner consistent with
part 75 of this chapter and §§ 97.530
through 97.535. The following systems
are the principal types of continuous
emission monitoring systems:
(1) A flow monitoring system,
consisting of a stack flow rate monitor
and an automated data acquisition and
handling system and providing a
permanent, continuous record of stack
gas volumetric flow rate, in standard
cubic feet per hour (scfh);
(2) A NOX concentration monitoring
system, consisting of a NOX pollutant
concentration monitor and an
automated data acquisition and
handling system and providing a
permanent, continuous record of NOX
emissions, in parts per million (ppm);
(3) A NOX emission rate (or NOXdiluent) monitoring system, consisting
of a NOX pollutant concentration
monitor, a diluent gas (CO2 or O2)
monitor, and an automated data
acquisition and handling system and
providing a permanent, continuous
record of NOX concentration, in parts
per million (ppm), diluent gas
concentration, in percent CO2 or O2, and
NOX emission rate, in pounds per
million British thermal units (lb/
mmBtu);
(4) A moisture monitoring system, as
defined in § 75.11(b)(2) of this chapter
and providing a permanent, continuous
record of the stack gas moisture content,
in percent H2O;
(5) A CO2 monitoring system,
consisting of a CO2 pollutant
concentration monitor (or an O2 monitor
plus suitable mathematical equations
from which the CO2 concentration is
derived) and an automated data
acquisition and handling system and
providing a permanent, continuous
record of CO2 emissions, in percent CO2;
and
(6) An O2 monitoring system,
consisting of an O2 concentration
monitor and an automated data
acquisition and handling system and
providing a permanent, continuous
record of O2, in percent O2.
Control period means the period
starting May 1 of a calendar year, except
as provided in § 97.506(c)(3), and
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ending on September 30 of the same
year, inclusive.
Designated representative means, for
a TR NOX Ozone Season source and
each TR NOX Ozone Season unit at the
source, the natural person who is
authorized by the owners and operators
of the source and all such units at the
source, in accordance with this subpart,
to represent and legally bind each
owner and operator in matters
pertaining to the TR NOX Ozone Season
Trading Program. If the TR NOX Ozone
Season source is also subject to the Acid
Rain Program, TR NOX Annual Trading
Program, TR SO2 Group 1 Trading
Program, or TR SO2 Group 2 Trading
Program, then this natural person shall
be the same natural person as the
designated representative, as defined in
the respective program.
Emissions means air pollutants
exhausted from a unit or source into the
atmosphere, as measured, recorded, and
reported to the Administrator by the
designated representative, and as
modified by the Administrator:
(1) In accordance with this subpart;
and
(2) With regard to a period before the
unit or source is required to measure,
record, and report such air pollutants in
accordance with this subpart, in
accordance with part 75 of this chapter.
Excess emissions means any ton of
emissions from the TR NOX Ozone
Season units at a TR NOX Ozone Season
source during a control period in a
given year that exceeds the TR NOX
Ozone Season emissions limitation for
the source for such control period.
Fossil fuel means—
(1) Natural gas, petroleum, coal, or
any form of solid, liquid, or gaseous fuel
derived from such material; or
(2) For purposes of applying the
limitation on ‘‘average annual fuel
consumption of fossil fuel’’ in
§§ 97.504(b)(2)(i)(B) and (ii), natural gas,
petroleum, coal, or any form of solid,
liquid, or gaseous fuel derived from
such material for the purpose of creating
useful heat.
Fossil-fuel-fired means, with regard to
a unit, combusting any amount of fossil
fuel in 2005 or any calendar year
thereafter.
General account means an Allowance
Management System account,
established under this subpart, that is
not a compliance account or an
assurance account.
Generator means a device that
produces electricity.
Gross electrical output means, for a
unit, electricity made available for use,
including any such electricity used in
the power production process (which
process includes, but is not limited to,
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any on-site processing or treatment of
fuel combusted at the unit and any onsite emission controls).
Heat input means, for a unit for a
specified period of time, the product (in
mmBtu/time) of the gross calorific value
of the fuel (in mmBtu/lb) fed into the
unit multiplied by the fuel feed rate (in
lb of fuel/time), as measured, recorded,
and reported to the Administrator by the
designated representative and as
modified by the Administrator in
accordance with this subpart and
excluding the heat derived from
preheated combustion air, recirculated
flue gases, or exhaust.
Heat input rate means, for a unit, the
amount of heat input (in mmBtu)
divided by unit operating time (in hr)
or, for a unit and a specific fuel, the
amount of heat input attributed to the
fuel (in mmBtu) divided by the unit
operating time (in hr) during which the
unit combusts the fuel.
Heat rate means, for a unit, the unit’s
maximum design heat input (in Btu/hr),
divided by the product of 1,000,000
Btu/mmBtu and the unit’s maximum
hourly load.
Indian country means ‘‘Indian
country’’ as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power
contractual arrangement means a unit
participation power sales agreement
under which a utility or industrial
customer reserves, or is entitled to
receive, a specified amount or
percentage of nameplate capacity and
associated energy generated by any
specified unit and pays its proportional
amount of such unit’s total costs,
pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less
than 30 years, including contracts that
permit an election for early termination;
or
(3) For a period no less than 25 years
or 70 percent of the economic useful life
of the unit determined as of the time the
unit is built, with option rights to
purchase or release some portion of the
nameplate capacity and associated
energy generated by the unit at the end
of the period.
Maximum design heat input means,
for a unit, the maximum amount of fuel
per hour (in Btu/hr) that the unit is
capable of combusting on a steady state
basis as of the initial installation of the
unit as specified by the manufacturer of
the unit.
Monitoring system means any
monitoring system that meets the
requirements of this subpart, including
a continuous emission monitoring
system, an alternative monitoring
system, or an excepted monitoring
system under part 75 of this chapter.
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Nameplate capacity means, starting
from the initial installation of a
generator, the maximum electrical
generating output (in MWe, rounded to
the nearest tenth) that the generator is
capable of producing on a steady state
basis and during continuous operation
(when not restricted by seasonal or
other deratings) as of such installation
as specified by the manufacturer of the
generator or, starting from the
completion of any subsequent physical
change in the generator resulting in an
increase in the maximum electrical
generating output that the generator is
capable of producing on a steady state
basis and during continuous operation
(when not restricted by seasonal or
other deratings), such increased
maximum amount (in MWe, rounded to
the nearest tenth) as of such completion
as specified by the person conducting
the physical change.
Natural gas means ‘‘natural gas’’ as
defined in § 72.2 of this chapter.
Newly affected TR NOX Ozone Season
unit means a unit that was not a TR NOX
Ozone Season unit when it began
operating but that thereafter becomes a
TR NOX Ozone Season unit.
Operate or operation means, with
regard to a unit, to combust fuel.
Operator means, for a TR NOX Ozone
Season source or a TR NOX Ozone
Season unit at a source respectively, any
person who operates, controls, or
supervises a TR NOX Ozone Season unit
at the source or the TR NOX Ozone
Season unit and shall include, but not
be limited to, any holding company,
utility system, or plant manager of such
source or unit.
Owner means, for a TR NOX Ozone
Season source or a TR NOX Ozone
Season unit at a source respectively, any
of the following persons:
(1) Any holder of any portion of the
legal or equitable title in a TR NOX
Ozone Season unit at the source or the
TR NOX Ozone Season unit;
(2) Any holder of a leasehold interest
in a TR NOX Ozone Season unit at the
source or the TR NOX Ozone Season
unit, provided that, unless expressly
provided for in a leasehold agreement,
‘‘owner’’ shall not include a passive
lessor, or a person who has an equitable
interest through such lessor, whose
rental payments are not based (either
directly or indirectly) on the revenues or
income from such TR NOX Ozone
Season unit; and
(3) Any purchaser of power from a TR
NOX Ozone Season unit at the source or
the TR NOX Ozone Season unit under a
life-of-the-unit, firm power contractual
arrangement.
Permanently retired means, with
regard to a unit, a unit that is
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unavailable for service and that the
unit’s owners and operators do not
expect to return to service in the future.
Permitting authority means
‘‘permitting authority’’ as defined in
§§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity
means, for a unit, 33 percent of the
unit’s maximum design heat input,
divided by 3,413 Btu/kWh, divided by
1,000 kWh/MWh, and multiplied by
8,760 hr/yr.
Receive or receipt of means, when
referring to the Administrator, to come
into possession of a document,
information, or correspondence
(whether sent in hard copy or by
authorized electronic transmission), as
indicated in an official log, or by a
notation made on the document,
information, or correspondence, by the
Administrator in the regular course of
business.
Recordation, record, or recorded
means, with regard to TR NOX Ozone
Season allowances, the moving of TR
NOX Ozone Season allowances by the
Administrator into, out of, or between
Allowance Management System
accounts, for purposes of allocation,
auction, transfer, or deduction.
Reference method means any direct
test method of sampling and analyzing
for an air pollutant as specified in
§ 75.22 of this chapter.
Replacement, replace, or replaced
means, with regard to a unit, the
demolishing of a unit, or the permanent
retirement and permanent disabling of a
unit, and the construction of another
unit (the replacement unit) to be used
instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from
electricity production in a useful
thermal energy application or process;
or
(2) The use of reject heat from useful
thermal energy application or process in
electricity production.
Serial number means, for a TR NOX
Ozone Season allowance, the unique
identification number assigned to each
TR NOX Ozone Season allowance by the
Administrator.
Solid waste incineration unit means a
stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion
turbine that is a ‘‘solid waste
incineration unit’’ as defined in section
129(g)(1) of the Clean Air Act.
Source means all buildings,
structures, or installations located in
one or more contiguous or adjacent
properties under common control of the
same person or persons. This definition
does not change or otherwise affect the
definition of ‘‘major source’’, ‘‘stationary
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source’’, or ‘‘source’’ as set forth and
implemented in a title V operating
permit program or any other program
under the Clean Air Act.
State means one of the States that is
subject to the TR NOX Ozone Season
Trading Program pursuant to § 52.38(b)
of this chapter.
Submit or serve means to send or
transmit a document, information, or
correspondence to the person specified
in accordance with the applicable
regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or
transmission and delivery;
(4) Provided that compliance with any
‘‘submission’’ or ‘‘service’’ deadline
shall be determined by the date of
dispatch, transmission, or mailing and
not the date of receipt.
Topping-cycle unit means a unit in
which the energy input to the unit is
first used to produce useful power,
including electricity, where at least
some of the reject heat from the
electricity production is then used to
provide useful thermal energy.
Total energy input means, for a unit,
total energy of all forms supplied to the
unit, excluding energy produced by the
unit. Each form of energy supplied shall
be measured by the lower heating value
of that form of energy calculated as
follows:
LHV = HHV ¥ 10.55 (W + 9H)
Where:
LHV = lower heating value of the form of
energy in Btu/lb,
HHV = higher heating value of the form of
energy in Btu/lb,
W = weight % of moisture in the form of
energy, and
H = weight % of hydrogen in the form of
energy.
Total energy output means, for a unit,
the sum of useful power and useful
thermal energy produced by the unit.
TR NOX Annual Trading Program
means a multi-state NOX air pollution
control and emission reduction program
established in accordance with subpart
AAAAA of this part and § 52.38(a) of
this chapter (including such a program
that is revised in a SIP revision
approved by the Administrator under
§ 52.38(a)(3) or (4) of this chapter or that
is established in a SIP revision approved
by the Administrator under § 52.38(a)(5)
of this chapter), as a means of mitigating
interstate transport of fine particulates
and NOX.
TR NOX Ozone Season allowance
means a limited authorization issued
and allocated or auctioned by the
Administrator under this subpart, or by
a State or permitting authority under a
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SIP revision approved by the
Administrator under § 52.38(b)(3), (4),
or (5) of this chapter, to emit one ton of
NOX during a control period of the
specified calendar year for which the
authorization is allocated or auctioned
or of any calendar year thereafter under
the TR NOX Ozone Season Trading
Program.
TR NOX Ozone Season allowance
deduction or deduct TR NOX Ozone
Season allowances means the
permanent withdrawal of TR NOX
Ozone Season allowances by the
Administrator from a compliance
account (e.g., in order to account for
compliance with the TR NOX Ozone
Season emissions limitation) or from an
assurance account (e.g., in order to
account for compliance with the
assurance provisions under §§ 97.506
and 97.525).
TR NOX Ozone Season allowances
held or hold TR NOX Ozone Season
allowances means the TR NOX Ozone
Season allowances treated as included
in an Allowance Management System
account as of a specified point in time
because at that time they:
(1) Have been recorded by the
Administrator in the account or
transferred into the account by a
correctly submitted, but not yet
recorded, TR NOX Ozone Season
allowance transfer in accordance with
this subpart; and
(2) Have not been transferred out of
the account by a correctly submitted,
but not yet recorded, TR NOX Ozone
Season allowance transfer in accordance
with this subpart.
TR NOX Ozone Season emissions
limitation means, for a TR NOX Ozone
Season source, the tonnage of NOX
emissions authorized in a control period
in a given year by the TR NOX Ozone
Season allowances available for
deduction for the source under
§ 97.524(a) for such control period.
TR NOX Ozone Season source means
a source that includes one or more TR
NOX Ozone Season units.
TR NOX Ozone Season Trading
Program means a multi-state NOX air
pollution control and emission
reduction program established in
accordance with this subpart and
§ 52.38(b) of this chapter (including
such a program that is revised in a SIP
revision approved by the Administrator
under § 52.38(b)(3) or (4) of this chapter
or that is established in a SIP revision
approved by the Administrator under
§ 52.38(b)(5) of this chapter), as a means
of mitigating interstate transport of
ozone and NOX.
TR NOX Ozone Season unit means a
unit that is subject to the TR NOX Ozone
Season Trading Program.
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TR SO2 Group 1 Trading Program
means a multi-state SO2 air pollution
control and emission reduction program
established in accordance with subpart
CCCCC of this part and 52.39(a), (b), (d)
through (f), (j), and (k) of this chapter
(including such a program that is
revised in a SIP revision approved by
the Administrator under § 52.39(d) or (e)
of this chapter or that is established in
a SIP revision approved by the
Administrator under § 52.39(f) of this
chapter), as a means of mitigating
interstate transport of fine particulates
and SO2.
TR SO2 Group 2 Trading Program
means a multi-state SO2 air pollution
control and emission reduction program
established in accordance with subpart
DDDDD of this part and 52.39(a), (c),
and (g) through (k) of this chapter
(including such a program that is
revised in a SIP revision approved by
the Administrator under § 52.39(g) or (h)
of this chapter or that is established in
a SIP revision approved by the
Administrator under § 52.39(i) of this
chapter), as a means of mitigating
interstate transport of fine particulates
and SO2.
Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired
combustion turbine, or other stationary,
fossil-fuel-fired combustion device. A
unit that undergoes a physical change or
is moved to a different location or
source shall continue to be treated as
the same unit. A unit (the replaced unit)
that is replaced by another unit (the
replacement unit) at the same or a
different source shall continue to be
treated as the same unit, and the
replacement unit shall be treated as a
separate unit.
Unit operating day means, with
regard to a unit, a calendar day in which
the unit combusts any fuel.
Unit operating hour or hour of unit
operation means, with regard to a unit,
an hour in which the unit combusts any
fuel.
Useful power means, with regard to a
unit, electricity or mechanical energy
that the unit makes available for use,
excluding any such energy used in the
power production process (which
process includes, but is not limited to,
any on-site processing or treatment of
fuel combusted at the unit and any onsite emission controls).
Useful thermal energy means thermal
energy that is:
(1) Made available to an industrial or
commercial process (not a power
production process), excluding any heat
contained in condensate return or
makeup water;
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(2) Used in a heating application (e.g.,
space heating or domestic hot water
heating); or
(3) Used in a space cooling
application (i.e., in an absorption
chiller).
Utility power distribution system
means the portion of an electricity grid
owned or operated by a utility and
dedicated to delivering electricity to
customers.
§ 97.503 Measurements, abbreviations,
and acronyms.
Measurements, abbreviations, and
acronyms used in this subpart are
defined as follows:
Btu—British thermal unit
CO2—carbon dioxide
H2O—water
hr—hour
kW—kilowatt electrical
kWh—kilowatt hour
lb—pound
mmBtu—million Btu
MWe—megawatt electrical
MWh—megawatt hour
NOX—nitrogen oxides
O2—oxygen
ppm—parts per million
scfh—standard cubic feet per hour
SO2—sulfur dioxide
yr—year
§ 97.504
Applicability.
(a) Except as provided in paragraph
(b) of this section:
(1) The following units in a State (and
Indian country within the borders of
such State) shall be TR NOX Ozone
Season units, and any source that
includes one or more such units shall be
a TR NOX Ozone Season source, subject
to the requirements of this subpart: any
stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion
turbine serving at any time, on or after
January 1, 2005, a generator with
nameplate capacity of more than 25
MWe producing electricity for sale.
(2) If a stationary boiler or stationary
combustion turbine that, under
paragraph (a)(1) of this section, is not a
TR NOX Ozone Season unit begins to
combust fossil fuel or to serve a
generator with nameplate capacity of
more than 25 MWe producing electricity
for sale, the unit shall become a TR NOX
Ozone Season unit as provided in
paragraph (a)(1) of this section on the
first date on which it both combusts
fossil fuel and serves such generator.
(b) Any unit in a State (and Indian
country within the borders of such
State) that otherwise is a TR NOX Ozone
Season unit under paragraph (a) of this
section and that meets the requirements
set forth in paragraph (b)(1)(i) or (2)(i) of
this section shall not be a TR NOX
Ozone Season unit:
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(1)(i) Any unit:
(A) Qualifying as a cogeneration unit
throughout the later of 2005 or the 12month period starting on the date the
unit first produces electricity and
continuing to qualify as a cogeneration
unit throughout each calendar year
ending after the later of 2005 or such
12-month period; and
(B) Not supplying in 2005 or any
calendar year thereafter more than onethird of the unit’s potential electric
output capacity or 219,000 MWh,
whichever is greater, to any utility
power distribution system for sale.
(ii) If, after qualifying under
paragraph (b)(1)(i) of this section as not
being a TR NOX Ozone Season unit, a
unit subsequently no longer meets all
the requirements of paragraph (b)(1)(i)
of this section, the unit shall become a
TR NOX Ozone Season unit starting on
the earlier of January 1 after the first
calendar year during which the unit first
no longer qualifies as a cogeneration
unit or January 1 after the first calendar
year during which the unit no longer
meets the requirements of paragraph
(b)(1)(i)(B) of this section. The unit shall
thereafter continue to be a TR NOX
Ozone Season unit.
(2)(i) Any unit:
(A) Qualifying as a solid waste
incineration unit throughout the later of
2005 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit
throughout each calendar year ending
after the later of 2005 or such 12-month
period; and
(B) With an average annual fuel
consumption of fossil fuel for the first
3 consecutive calendar years of
operation starting no earlier than 2005
of less than 20 percent (on a Btu basis)
and an average annual fuel consumption
of fossil fuel for any 3 consecutive
calendar years thereafter of less than 20
percent (on a Btu basis).
(ii) If, after qualifying under
paragraph (b)(2)(i) of this section as not
being a TR NOX Ozone Season unit, a
unit subsequently no longer meets all
the requirements of paragraph (b)(1)(i)
of this section, the unit shall become a
TR NOX Ozone Season unit starting on
the earlier of January 1 after the first
calendar year during which the unit first
no longer qualifies as a solid waste
incineration unit or January 1 after the
first 3 consecutive calendar years after
2005 for which the unit has an average
annual fuel consumption of fossil fuel of
20 percent or more. The unit shall
thereafter continue to be a TR NOX
Ozone Season unit.
(c) A certifying official of an owner or
operator of any unit or other equipment
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may submit a petition (including any
supporting documents) to the
Administrator at any time for a
determination concerning the
applicability, under paragraphs (a) and
(b) of this section or a SIP revision
approved under § 52.38(b)(4) or (5) of
this chapter, of the TR NOX Ozone
Season Trading Program to the unit or
other equipment.
(1) Petition content. The petition shall
be in writing and include the
identification of the unit or other
equipment and the relevant facts about
the unit or other equipment. The
petition and any other documents
provided to the Administrator in
connection with the petition shall
include the following certification
statement, signed by the certifying
official: ‘‘I am authorized to make this
submission on behalf of the owners and
operators of the unit or other equipment
for which the submission is made. I
certify under penalty of law that I have
personally examined, and am familiar
with, the statements and information
submitted in this document and all its
attachments. Based on my inquiry of
those individuals with primary
responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(2) Response. The Administrator will
issue a written response to the petition
and may request supplemental
information determined by the
Administrator to be relevant to such
petition. The Administrator’s
determination concerning the
applicability, under paragraphs (a) and
(b) of this section, of the TR NOX Ozone
Season Trading Program to the unit or
other equipment shall be binding on any
State or permitting authority unless the
Administrator determines that the
petition or other documents or
information provided in connection
with the petition contained significant,
relevant errors or omissions.
ebenthall on DSK6TPTVN1PROD with RULES2
§ 97.505
Retired unit exemption.
(a)(1) Any TR NOX Ozone Season unit
that is permanently retired shall be
exempt from § 97.506(b) and (c)(1),
§ 97.524, and §§ 97.530 through 97.535.
(2) The exemption under paragraph
(a)(1) of this section shall become
effective the day on which the TR NOX
Ozone Season unit is permanently
retired. Within 30 days of the unit’s
permanent retirement, the designated
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19:20 Aug 05, 2011
Jkt 223001
representative shall submit a statement
to the Administrator. The statement
shall state, in a format prescribed by the
Administrator, that the unit was
permanently retired on a specified date
and will comply with the requirements
of paragraph (b) of this section.
(b) Special provisions. (1) A unit
exempt under paragraph (a) of this
section shall not emit any NOX, starting
on the date that the exemption takes
effect.
(2) For a period of 5 years from the
date the records are created, the owners
and operators of a unit exempt under
paragraph (a) of this section shall retain,
at the source that includes the unit,
records demonstrating that the unit is
permanently retired. The 5-year period
for keeping records may be extended for
cause, at any time before the end of the
period, in writing by the Administrator.
The owners and operators bear the
burden of proof that the unit is
permanently retired.
(3) The owners and operators and, to
the extent applicable, the designated
representative of a unit exempt under
paragraph (a) of this section shall
comply with the requirements of the TR
NOX Ozone Season Trading Program
concerning all periods for which the
exemption is not in effect, even if such
requirements arise, or must be complied
with, after the exemption takes effect.
(4) A unit exempt under paragraph (a)
of this section shall lose its exemption
on the first date on which the unit
resumes operation. Such unit shall be
treated, for purposes of applying
allocation, monitoring, reporting, and
recordkeeping requirements under this
subpart, as a unit that commences
commercial operation on the first date
on which the unit resumes operation.
§ 97.506
Standard requirements.
(a) Designated representative
requirements. The owners and operators
shall comply with the requirement to
have a designated representative, and
may have an alternate designated
representative, in accordance with
§§ 97.513 through 97.518.
(b) Emissions monitoring, reporting,
and recordkeeping requirements. (1)
The owners and operators, and the
designated representative, of each TR
NOX Ozone Season source and each TR
NOX Ozone Season unit at the source
shall comply with the monitoring,
reporting, and recordkeeping
requirements of §§ 97.530 through
97.535.
(2) The emissions data determined in
accordance with §§ 97.530 through
97.535 shall be used to calculate
allocations of TR NOX Ozone Season
allowances under §§ 97.511(a)(2) and (b)
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Sfmt 4700
and 97.512 and to determine
compliance with the TR NOX Ozone
Season emissions limitation and
assurance provisions under paragraph
(c) of this section, provided that, for
each monitoring location from which
mass emissions are reported, the mass
emissions amount used in calculating
such allocations and determining such
compliance shall be the mass emissions
amount for the monitoring location
determined in accordance with
§§ 97.530 through 97.535 and rounded
to the nearest ton, with any fraction of
a ton less than 0.50 being deemed to be
zero.
(c) NOX emissions requirements. (1)
TR NOX Ozone Season emissions
limitation. (i) As of the allowance
transfer deadline for a control period in
a given year, the owners and operators
of each TR NOX Ozone Season source
and each TR NOX Ozone Season unit at
the source shall hold, in the source’s
compliance account, TR NOX Ozone
Season allowances available for
deduction for such control period under
§ 97.524(a) in an amount not less than
the tons of total NOX emissions for such
control period from all TR NOX Ozone
Season units at the source.
(ii) If total NOX emissions during a
control period in a given year from the
TR NOX Ozone Season units at a TR
NOX Ozone Season source are in excess
of the TR NOX Ozone Season emissions
limitation set forth in paragraph (c)(1)(i)
of this section, then:
(A) The owners and operators of the
source and each TR NOX Ozone Season
unit at the source shall hold the TR NOX
Ozone Season allowances required for
deduction under § 97.524(d); and
(B) The owners and operators of the
source and each TR NOX Ozone Season
unit at the source shall pay any fine,
penalty, or assessment or comply with
any other remedy imposed, for the same
violations, under the Clean Air Act, and
each ton of such excess emissions and
each day of such control period shall
constitute a separate violation of this
subpart and the Clean Air Act.
(2) TR NOX Ozone Season assurance
provisions. (i) If total NOX emissions
during a control period in a given year
from all TR NOX Ozone Season units at
TR NOX Ozone Season sources in a
State (and Indian country within the
borders of such State) exceed the State
assurance level, then the owners and
operators of such sources and units in
each group of one or more sources and
units having a common designated
representative for such control period,
where the common designated
representative’s share of such NOX
emissions during such control period
exceeds the common designated
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representative’s assurance level for the
State and such control period, shall
hold (in the assurance account
established for the owners and operators
of such group) TR NOX Ozone Season
allowances available for deduction for
such control period under § 97.525(a) in
an amount equal to two times the
product (rounded to the nearest whole
number), as determined by the
Administrator in accordance with
§ 97.525(b), of multiplying—
(A) The quotient of the amount by
which the common designated
representative’s share of such NOX
emissions exceeds the common
designated representative’s assurance
level divided by the sum of the
amounts, determined for all common
designated representatives for such
sources and units in the State (and
Indian country within the borders of
such State) for such control period, by
which each common designated
representative’s share of such NOX
emissions exceeds the respective
common designated representative’s
assurance level; and
(B) The amount by which total NOX
emissions from all TR NOX Ozone
Season units at TR NOX Ozone Season
sources in the State (and Indian country
within the borders of such State) for
such control period exceed the State
assurance level.
(ii) The owners and operators shall
hold the TR NOX Ozone Season
allowances required under paragraph
(c)(2)(i) of this section, as of midnight of
November 1 (if it is a business day), or
midnight of the first business day
thereafter (if November 1 is not a
business day), immediately after such
control period.
(iii) Total NOX emissions from all TR
NOX Ozone Season units at TR NOX
Ozone Season sources in a State (and
Indian country within the borders of
such State) during a control period in a
given year exceed the State assurance
level if such total NOX emissions exceed
the sum, for such control period, of the
State NOX Ozone Season trading budget
under § 97.510(a) and the State’s
variability limit under § 97.510(b).
(iv) It shall not be a violation of this
subpart or of the Clean Air Act if total
NOX emissions from all TR NOX Ozone
Season units at TR NOX Ozone Season
sources in a State (and Indian country
within the borders of such State) during
a control period exceed the State
assurance level or if a common
designated representative’s share of total
NOX emissions from the TR NOX Ozone
Season units at TR NOX Ozone Season
sources in a State (and Indian country
within the borders of such State) during
a control period exceeds the common
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19:20 Aug 05, 2011
Jkt 223001
designated representative’s assurance
level.
(v) To the extent the owners and
operators fail to hold TR NOX Ozone
Season allowances for a control period
in a given year in accordance with
paragraphs (c)(2)(i) through (iii) of this
section,
(A) The owners and operators shall
pay any fine, penalty, or assessment or
comply with any other remedy imposed
under the Clean Air Act; and
(B) Each TR NOX Ozone Season
allowance that the owners and operators
fail to hold for such control period in
accordance with paragraphs (c)(2)(i)
through (iii) of this section and each day
of such control period shall constitute a
separate violation of this subpart and
the Clean Air Act.
(3) Compliance periods. A TR NOX
Ozone Season unit shall be subject to
the requirements under paragraphs
(c)(1) and (c)(2) of this section for the
control period starting on the later of
May 1, 2012 or the deadline for meeting
the unit’s monitor certification
requirements under § 97.530(b) and for
each control period thereafter.
(4) Vintage of allowances held for
compliance. (i) A TR NOX Ozone Season
allowance held for compliance with the
requirements under paragraph (c)(1)(i)
of this section for a control period in a
given year must be a TR NOX Ozone
Season allowance that was allocated for
such control period or a control period
in a prior year.
(ii) A TR NOX Ozone Season
allowance held for compliance with the
requirements under paragraphs
(c)(1)(ii)(A) and (2)(i) through (iii) of this
section for a control period in a given
year must be a TR NOX Ozone Season
allowance that was allocated for a
control period in a prior year or the
control period in the given year or in the
immediately following year.
(5) Allowance Management System
requirements. Each TR NOX Ozone
Season allowance shall be held in,
deducted from, or transferred into, out
of, or between Allowance Management
System accounts in accordance with
this subpart.
(6) Limited authorization. A TR NOX
Ozone Season allowance is a limited
authorization to emit one ton of NOX
during the control period in one year.
Such authorization is limited in its use
and duration as follows:
(i) Such authorization shall only be
used in accordance with the TR NOX
Ozone Season Trading Program; and
(ii) Notwithstanding any other
provision of this subpart, the
Administrator has the authority to
terminate or limit the use and duration
of such authorization to the extent the
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48413
Administrator determines is necessary
or appropriate to implement any
provision of the Clean Air Act.
(7) Property right. A TR NOX Ozone
Season allowance does not constitute a
property right.
(d) Title V permit requirements. (1) No
title V permit revision shall be required
for any allocation, holding, deduction,
or transfer of TR NOX Ozone Season
allowances in accordance with this
subpart.
(2) A description of whether a unit is
required to monitor and report NOX
emissions using a continuous emission
monitoring system (under subpart H of
part 75 of this chapter), an excepted
monitoring system (under appendices D
and E to part 75 of this chapter), a low
mass emissions excepted monitoring
methodology (under § 75.19 of this
chapter), or an alternative monitoring
system (under subpart E of part 75 of
this chapter) in accordance with
§§ 97.530 through 97.535 may be added
to, or changed in, a title V permit using
minor permit modification procedures
in accordance with §§ 70.7(e)(2) and
71.7(e)(1) of this chapter, provided that
the requirements applicable to the
described monitoring and reporting (as
added or changed, respectively) are
already incorporated in such permit.
This paragraph explicitly provides that
the addition of, or change to, a unit’s
description as described in the prior
sentence is eligible for minor permit
modification procedures in accordance
with §§ 70.7(e)(2)(i)(B) and
71.7(e)(1)(i)(B) of this chapter.
(e) Additional recordkeeping and
reporting requirements. (1) Unless
otherwise provided, the owners and
operators of each TR NOX Ozone Season
source and each TR NOX Ozone Season
unit at the source shall keep on site at
the source each of the following
documents (in hardcopy or electronic
format) for a period of 5 years from the
date the document is created. This
period may be extended for cause, at
any time before the end of 5 years, in
writing by the Administrator.
(i) The certificate of representation
under § 97.516 for the designated
representative for the source and each
TR NOX Ozone Season unit at the
source and all documents that
demonstrate the truth of the statements
in the certificate of representation;
provided that the certificate and
documents shall be retained on site at
the source beyond such 5-year period
until such certificate of representation
and documents are superseded because
of the submission of a new certificate of
representation under § 97.516 changing
the designated representative.
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08AUR2
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
(ii) All emissions monitoring
information, in accordance with this
subpart.
(iii) Copies of all reports, compliance
certifications, and other submissions
and all records made or required under,
or to demonstrate compliance with the
requirements of, the TR NOX Ozone
Season Trading Program.
(2) The designated representative of a
TR NOX Ozone Season source and each
TR NOX Ozone Season unit at the
source shall make all submissions
required under the TR NOX Ozone
Season Trading Program, except as
provided in § 97.518. This requirement
does not change, create an exemption
from, or otherwise affect the responsible
official submission requirements under
a title V operating permit program in
parts 70 and 71 of this chapter.
(f) Liability. (1) Any provision of the
TR NOX Ozone Season Trading Program
that applies to a TR NOX Ozone Season
source or the designated representative
of a TR NOX Ozone Season source shall
also apply to the owners and operators
of such source and of the TR NOX
Ozone Season units at the source.
(2) Any provision of the TR NOX
Ozone Season Trading Program that
applies to a TR NOX Ozone Season unit
or the designated representative of a TR
NOX Ozone Season unit shall also apply
to the owners and operators of such
unit.
(g) Effect on other authorities. No
provision of the TR NOX Ozone Season
Trading Program or exemption under
§ 97.505 shall be construed as
exempting or excluding the owners and
operators, and the designated
representative, of a TR NOX Ozone
Season source or TR NOX Ozone Season
unit from compliance with any other
provision of the applicable, approved
State implementation plan, a federally
enforceable permit, or the Clean Air Act.
§ 97.507
Computation of time.
(a) Unless otherwise stated, any time
period scheduled, under the TR NOX
Ozone Season Trading Program, to begin
on the occurrence of an act or event
shall begin on the day the act or event
occurs.
(b) Unless otherwise stated, any time
period scheduled, under the TR NOX
Ozone Season Trading Program, to begin
ebenthall on DSK6TPTVN1PROD with RULES2
§ 97.509
[Reserved]
§ 97.510 State NOX Ozone Season trading
budgets, new unit set-asides, Indian
country new unit set-aside, and variability
limits.
(a) The State NOX Ozone Season
trading budgets, new unit set-asides,
and Indian country new unit set-asides
for allocations of TR NOX Ozone Season
allowances for the control periods in
2012 and thereafter are as follows:
Indian country new
unit set-aside (tons)
for 2012 and 2013
31,746
15,037
27,825
27,944
21,208
46,876
36,167
13,432
7,179
10,160
3,382
8,331
22,168
40,063
52,201
13,909
14,908
63,043
14,452
25,283
635
301
529
559
1,697
1,406
1,447
390
144
193
68
242
1,308
801
1,044
264
298
1,828
723
1,264
................................
................................
28
................................
................................
................................
................................
13
................................
10
................................
8
22
................................
................................
14
................................
63
................................
................................
NOX Ozone Season trading budget
(tons) * for 2014
and thereafter
State
New unit set-aside
(tons) for 2014 and
thereafter
Indian country new
unit set-aside (tons)
for 2014 and thereafter
31,499
15,037
27,825
18,279
21,208
46,175
32,674
13,432
7,179
10,160
3,382
630
301
529
366
1,697
1,385
1,307
390
144
193
68
................................
................................
28
................................
................................
................................
................................
13
................................
10
................................
Alabama ...............................................................................................................
Arkansas ..............................................................................................................
Florida ..................................................................................................................
Georgia ................................................................................................................
Illinois ...................................................................................................................
Indiana .................................................................................................................
Kentucky ..............................................................................................................
Louisiana ..............................................................................................................
Maryland ..............................................................................................................
Mississippi ............................................................................................................
New Jersey ..........................................................................................................
Jkt 223001
The administrative appeal procedures
for decisions of the Administrator under
the TR NOX Ozone Season Trading
Program are set forth in part 78 of this
chapter.
New unit set-aside
(tons) for 2012 and
2013
Alabama ...............................................................................................................
Arkansas ..............................................................................................................
Florida ..................................................................................................................
Georgia ................................................................................................................
Illinois ...................................................................................................................
Indiana .................................................................................................................
Kentucky ..............................................................................................................
Louisiana ..............................................................................................................
Maryland ..............................................................................................................
Mississippi ............................................................................................................
New Jersey ..........................................................................................................
New York .............................................................................................................
North Carolina ......................................................................................................
Ohio .....................................................................................................................
Pennsylvania ........................................................................................................
South Carolina .....................................................................................................
Tennessee ...........................................................................................................
Texas ...................................................................................................................
Virginia .................................................................................................................
West Virginia ........................................................................................................
19:20 Aug 05, 2011
§ 97.508 Administrative appeal
procedures.
NOX Ozone Season trading budget
(tons) * for 2012
and 2013
State
VerDate Mar<15>2010
before the occurrence of an act or event
shall be computed so that the period
ends the day before the act or event
occurs.
(c) Unless otherwise stated, if the final
day of any time period, under the TR
NOX Ozone Season Trading Program, is
not a business day, the time period shall
be extended to the next business day.
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48415
NOX Ozone Season trading budget
(tons) * for 2014
and thereafter
State
New unit set-aside
(tons) for 2014 and
thereafter
Indian country new
unit set-aside (tons)
for 2014 and thereafter
8,331
18,455
37,792
51,912
13,909
8,016
63,043
14,452
23,291
242
1,089
756
1,038
264
160
1,828
723
1,165
8
18
................................
................................
14
................................
63
................................
................................
New York .............................................................................................................
North Carolina ......................................................................................................
Ohio .....................................................................................................................
Pennsylvania ........................................................................................................
South Carolina .....................................................................................................
Tennessee ...........................................................................................................
Texas ...................................................................................................................
Virginia .................................................................................................................
West Virginia ........................................................................................................
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-aside and does not include the
variability limit.
(b) The States’ variability limits for
the State NOX Ozone Season trading
budgets for the control periods in 2012
and thereafter are as follows:
Variability limits for
2012 and 2013
State
Variability limits for
2014 and thereafter
6,667
3,158
5,843
5,868
4,454
9,844
7,595
2,821
1,508
2,134
710
1,750
4,655
8,413
10,962
2,921
3,131
13,239
3,035
5,309
6,615
3,158
5,843
3,839
4,454
9,697
6,862
2,821
1,508
2,134
710
1,750
3,876
7,936
10,902
2,921
1,683
13,239
3,035
4,891
Alabama ...................................................................................................................................................
Arkansas ..................................................................................................................................................
Florida ......................................................................................................................................................
Georgia ....................................................................................................................................................
Illinois .......................................................................................................................................................
Indiana .....................................................................................................................................................
Kentucky ..................................................................................................................................................
Louisiana ..................................................................................................................................................
Maryland ..................................................................................................................................................
Mississippi ................................................................................................................................................
New Jersey ..............................................................................................................................................
New York .................................................................................................................................................
North Carolina ..........................................................................................................................................
Ohio .........................................................................................................................................................
Pennsylvania ............................................................................................................................................
South Carolina .........................................................................................................................................
Tennessee ...............................................................................................................................................
Texas .......................................................................................................................................................
Virginia .....................................................................................................................................................
West Virginia ............................................................................................................................................
ebenthall on DSK6TPTVN1PROD with RULES2
§ 97.511 Timing requirements for TR NOX
Ozone Season allowance allocations.
(a) Existing units. (1) TR NOX Ozone
Season allowances are allocated, for the
control periods in 2012 and each year
thereafter, as provided in a notice of
data availability issued by the
Administrator. Providing an allocation
to a unit in such notice does not
constitute a determination that the unit
is a TR NOX Ozone Season unit, and not
providing an allocation to a unit in such
notice does not constitute a
determination that the unit is not a TR
NOX Ozone Season unit.
(2) Notwithstanding paragraph (a)(1)
of this section, if a unit provided an
allocation in the notice of data
availability issued under paragraph
(a)(1) of this section does not operate,
starting after 2011, during the control
period in two consecutive years, such
unit will not be allocated the TR NOX
Ozone Season allowances provided in
such notice for the unit for the control
periods in the fifth year after the first
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19:20 Aug 05, 2011
Jkt 223001
such year and in each year after that
fifth year. All TR NOX Ozone Season
allowances that would otherwise have
been allocated to such unit will be
allocated to the new unit set-aside for
the State where such unit is located and
for the respective years involved. If such
unit resumes operation, the
Administrator will allocate TR NOX
Ozone Season allowances to the unit in
accordance with paragraph (b) of this
section.
(b) New units.—(1) New unit setasides. (i) By June 1, 2012 and June 1
of each year thereafter, the
Administrator will calculate the TR
NOX Ozone Season allowance allocation
to each TR NOX Ozone Season unit in
a State, in accordance with
§ 97.512(a)(2) through (7) and (12), for
the control period in the year of the
applicable calculation deadline under
this paragraph and will promulgate a
notice of data availability of the results
of the calculations.
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(ii) For each notice of data availability
required in paragraph (b)(1)(i) of this
section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(1)(i) of this section and shall be
limited to addressing whether the
calculations (including the
identification of the TR NOX Ozone
Season units) are in accordance with
§ 97.512(a)(2) through (7) and (12) and
§§ 97.506(b)(2) and 97.530 through
97.535.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(1)(ii)(A) of this section. By August 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(1)(i) of this section, the
Administrator will promulgate a notice
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of data availability of any adjustments
that the Administrator determines to be
necessary with regard to allocations
under § 97.512(a)(2) through (7) and (12)
and the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(1)(ii)(A)
of this section.
(iii) If the new unit set-aside for such
control period contains any TR NOX
Ozone Season allowances that have not
been allocated in the applicable notice
of data availability required in
paragraph (b)(1)(ii) of this section, the
Administrator will promulgate, by
September 15 immediately after such
notice, a notice of data availability that
identifies any TR NOX Ozone Season
units that commenced commercial
operation during the period starting
May 1 of the year before the year of such
control period and ending August 31 of
year of such control period.
(iv) For each notice of data
availability required in paragraph
(b)(1)(iii) of this section, the
Administrator will provide an
opportunity for submission of objections
to the identification of TR NOX Ozone
Season units in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(1)(iii) of this section and shall be
limited to addressing whether the
identification of TR NOX Ozone Season
units in such notice is in accordance
with paragraph (b)(1)(iii) of this section.
(B) The Administrator will adjust the
identification of TR NOX Ozone Season
units in the each notice of data
availability required in paragraph
(b)(1)(iii) of this section to the extent
necessary to ensure that it is in
accordance with paragraph (b)(1)(iii) of
this section and will calculate the TR
NOX Ozone Season allowance allocation
to each TR NOX Ozone Season unit in
accordance with § 97.512(a)(9), (10), and
(12) and §§ 97.506(b)(2) and 97.530
through 97.535. By November 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(1)(iii) of this section,
the Administrator will promulgate a
notice of data availability of any
adjustments of the identification of TR
NOX Ozone Season units that the
Administrator determines to be
necessary, the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(1)(iv)(A)
of this section, and the results of such
calculations.
(v) To the extent any TR NOX Ozone
Season allowances are added to the new
unit set-aside after promulgation of each
notice of data availability required in
paragraph (b)(1)(iv) of this section, the
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Administrator will promulgate
additional notices of data availability, as
deemed appropriate, of the allocation of
such TR NOX Ozone Season allowances
in accordance with § 97.512(a)(10).
(2) Indian country new unit setasides. (i) By June 1, 2012 and June 1
of each year thereafter, the
Administrator will calculate the TR
NOX Ozone Season allowance allocation
to each TR NOX Ozone Season unit in
Indian country within the borders of a
State, in accordance with § 97.512(b)(2)
through (7) and (12), for the control
period in the year of the applicable
calculation deadline under this
paragraph and will promulgate a notice
of data availability of the results of the
calculations.
(ii) For each notice of data availability
required in paragraph (b)(2)(i) of this
section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(2)(i) of this section and shall be
limited to addressing whether the
calculations (including the
identification of the TR NOX Ozone
Season units) are in accordance with
§ 97.512(b)(2) through (7) and (12) and
§§ 97.506(b)(2) and 97.530 through
97.535.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(2)(ii)(A) of this section. By August 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(i) of this section, the
Administrator will promulgate a notice
of data availability of any adjustments
that the Administrator determines to be
necessary with regard to allocations
under § 97.512(b)(2) through (7) and (12)
and the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(2)(ii)(A)
of this section.
(iii) If the Indian country new unit
set-aside for such control period
contains any TR NOX Ozone Season
allowances that have not been allocated
in the applicable notice of data
availability required in paragraph
(b)(2)(ii) of this section, the
Administrator will promulgate, by
September 15 immediately after such
notice, a notice of data availability that
identifies any TR NOX Ozone Season
units that commenced commercial
operation during the period starting
May 1 of the year before the year of such
control period and ending August 31 of
year of such control period.
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(iv) For each notice of data
availability required in paragraph
(b)(2)(iii) of this section, the
Administrator will provide an
opportunity for submission of objections
to the identification of TR NOX Ozone
Season units in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(2)(iii) of this section and shall be
limited to addressing whether the
identification of TR NOX Ozone Season
units in such notice is in accordance
with paragraph (b)(2)(iii) of this section.
(B) The Administrator will adjust the
identification of TR NOX Ozone Season
units in the each notice of data
availability required in paragraph
(b)(2)(iii) of this section to the extent
necessary to ensure that it is in
accordance with paragraph (b)(2)(iii) of
this section and will calculate the TR
NOX Ozone Season allowance allocation
to each TR NOX Ozone Season unit in
accordance with § 97.512(b)(9), (10), and
(12) and §§ 97.506(b)(2) and 97.530
through 97.535. By November 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(iii) of this section,
the Administrator will promulgate a
notice of data availability of any
adjustments of the identification of TR
NOX Ozone Season units that the
Administrator determines to be
necessary, the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(2)(iv)(A)
of this section, and the results of such
calculations. (v) To the extent any TR
NOX Ozone Season allowances are
added to the Indian country new unit
set-aside after promulgation of each
notice of data availability required in
paragraph (b)(2)(iv) of this section, the
Administrator will promulgate
additional notices of data availability, as
deemed appropriate, of the allocation of
such TR NOX Ozone Season allowances
in accordance with § 97.512(b)(10).
(c) Units incorrectly allocated TR NOX
Ozone Season allowances. (1) For each
control period in 2012 and thereafter, if
the Administrator determines that TR
NOX Ozone Season allowances were
allocated under paragraph (a) of this
section, or under a provision of a SIP
revision approved under § 52.38(b)(3),
(4), or (5) of this chapter, where such
control period and the recipient are
covered by the provisions of paragraph
(c)(1)(i) of this section or were allocated
under § 97.512(a)(2) through (7), (9), and
(12) and (b)(2) through (7), (9), and (12),
or under a provision of a SIP revision
approved under § 52.38(b)(4) or (5) of
this chapter, where such control period
and the recipient are covered by the
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provisions of paragraph (c)(1)(ii) of this
section, then the Administrator will
notify the designated representative of
the recipient and will act in accordance
with the procedures set forth in
paragraphs (c)(2) through (5) of this
section:
(i)(A) The recipient is not actually a
TR NOX Ozone Season unit under
§ 97.504 as of May 1, 2012 and is
allocated TR NOX Ozone Season
allowances for such control period or, in
the case of an allocation under a
provision of a SIP revision approved
under § 52.38(b)(3), (4), or (5) of this
chapter, the recipient is not actually a
TR NOX Ozone Season unit as of May
1, 2012 and is allocated TR NOX Ozone
Season allowances for such control
period that the SIP revision provides
should be allocated only to recipients
that are TR NOX Ozone Season units as
of May 1, 2012; or
(B) The recipient is not located as of
May 1 of the control period in the State
from whose NOX Ozone Season trading
budget the TR NOX Ozone Season
allowances allocated under paragraph
(a) of this section, or under a provision
of a SIP revision approved under
§ 52.38(b)(3), (4), or (5) of this chapter,
were allocated for such control period.
(ii) The recipient is not actually a TR
NOX Ozone Season unit under § 97.504
as of May 1 of such control period and
is allocated TR NOX Ozone Season
allowances for such control period or, in
the case of an allocation under a
provision of a SIP revision approved
under § 52.38(b)(3), (4), or (5) of this
chapter, the recipient is not actually a
TR NOX Ozone Season unit as of
January 1 of such control period and is
allocated TR NOX Ozone Season
allowances for such control period that
the SIP revision provides should be
allocated only to recipients that are TR
NOX Ozone Season units as of May 1 of
such control period.
(2) Except as provided in paragraph
(c)(3) or (4) of this section, the
Administrator will not record such TR
NOX Ozone Season allowances under
§ 97.521.
(3) If the Administrator already
recorded such TR NOX Ozone Season
allowances under § 97.521 and if the
Administrator makes the determination
under paragraph (c)(1) of this section
before making deductions for the source
that includes such recipient under
§ 97.524(b) for such control period, then
the Administrator will deduct from the
account in which such TR NOX Ozone
Season allowances were recorded an
amount of TR NOX Ozone Season
allowances allocated for the same or a
prior control period equal to the amount
of such already recorded TR NOX Ozone
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Jkt 223001
Season allowances. The authorized
account representative shall ensure that
there are sufficient TR NOX Ozone
Season allowances in such account for
completion of the deduction.
(4) If the Administrator already
recorded such TR NOX Ozone Season
allowances under § 97.521 and if the
Administrator makes the determination
under paragraph (c)(1) of this section
after making deductions for the source
that includes such recipient under
§ 97.524(b) for such control period, then
the Administrator will not make any
deduction to take account of such
already recorded TR NOX Ozone Season
allowances.
(5)(i) With regard to the TR NOX
Ozone Season allowances that are not
recorded, or that are deducted as an
incorrect allocation, in accordance with
paragraphs (c)(2) and (3) of this section
for a recipient under paragraph (c)(1)(i)
of this section, the Administrator will:
(A) Transfer such TR NOX Ozone
Season allowances to the new unit setaside for such control period for the
State from whose NOX Ozone Season
trading budget the TR NOX Ozone
Season allowances were allocated; or
(B) If the State has a SIP revision
approved under § 52.38(b)(4) or (5)
covering such control period, include
such TR NOX Annual allowances in the
portion of the State NOX Ozone Season
trading budget that may be allocated for
such control period in accordance with
such SIP revision.
(ii) With regard to the TR NOX Ozone
Season allowances that were not
allocated from the Indian country new
unit set-aside for such control period
and that are not recorded, or that are
deducted as an incorrect allocation, in
accordance with paragraphs (c)(2) and
(3) of this section for a recipient under
paragraph (c)(1)(ii) of this paragraph, the
Administrator will:
(A) Transfer such TR NOX Ozone
Season allowances to the new unit setaside for such control period; or
(B) If the State has a SIP revision
approved under § 52.38(b)(4) or (5)
covering such control period, include
such TR NOX Ozone Season allowances
in the portion of the State NOX Ozone
Season trading budget that may be
allocated for such control period in
accordance with such SIP revision.
(iii) With regard to the TR NOX Ozone
Season allowances that were allocated
from the Indian country new unit setaside for such control period and that
are not recorded, or that are deducted as
an incorrect allocation, in accordance
with paragraphs (c)(2) and (3) of this
section for a recipient under paragraph
(c)(1)(ii) of this paragraph, the
Administrator will transfer such TR
PO 00000
Frm 00211
Fmt 4701
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48417
NOX Ozone Season allowances to the
Indian country new unit set-aside for
such control period.
§ 97.512 TR NOX Ozone Season allowance
allocations to new units.
(a) For each control period in 2012
and thereafter and for the TR NOX
Ozone Season units in each State, the
Administrator will allocate TR NOX
Ozone Season allowances to the TR
NOX Ozone Season units as follows:
(1) The TR NOX Ozone Season
allowances will be allocated to the
following TR NOX Ozone Season units,
except as provided in paragraph (a)(10)
of this section:
(i) TR NOX Ozone Season units that
are not allocated an amount of TR NOX
Ozone Season allowances in the notice
of data availability issued under
§ 97.511(a)(1);
(ii) TR NOX Ozone Season units
whose allocation of an amount of TR
NOX Ozone Season allowances for such
control period in the notice of data
availability issued under § 97.511(a)(1)
is covered by § 97.511(c)(2) or (3);
(iii) TR NOX Ozone Season units that
are allocated an amount of TR NOX
Ozone Season allowances for such
control period in the notice of data
availability issued under § 97.511(a)(1),
which allocation is terminated for such
control period pursuant to
§ 97.511(a)(2), and that operate during
the control period immediately
preceding such control period; or
(iv) For purposes of paragraph (a)(9)
of this section, TR NOX Ozone Season
units under § 97.511(c)(1)(ii) whose
allocation of an amount of TR NOX
Ozone Season allowances for such
control period in the notice of data
availability issued under
§ 97.511(b)(1)(ii)(B) is covered by
§ 97.511(c)(2) or (3).
(2) The Administrator will establish a
separate new unit set-aside for the State
for each such control period. Each such
new unit set-aside will be allocated TR
NOX Ozone Season allowances in an
amount equal to the applicable amount
of tons of NOX emissions as set forth in
§ 97.510(a) and will be allocated
additional TR NOX Ozone Season
allowances (if any) in accordance with
§§ 97.511(a)(2) and (c)(5) and paragraph
(b)(10) of this section.
(3) The Administrator will determine,
for each TR NOX Ozone Season unit
described in paragraph (a)(1) of this
section, an allocation of TR NOX Ozone
Season allowances for the later of the
following control periods and for each
subsequent control period:
(i) The control period in 2012;
(ii) The first control period after the
control period in which the TR NOX
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Ozone Season unit commences
commercial operation;
(iii) For a unit described in paragraph
(a)(1)(ii) of this section, the first control
period in which the TR NOX Ozone
Season unit operates in the State after
operating in another jurisdiction and for
which the unit is not already allocated
one or more TR NOX Ozone Season
allowances; and
(iv) For a unit described in paragraph
(a)(1)(iii) of this section, the first control
period after the control period in which
the unit resumes operation.
(4)(i) The allocation to each TR NOX
Ozone Season unit described in
paragraph (a)(1)(i) through (iii) of this
section and for each control period
described in paragraph (a)(3) of this
section will be an amount equal to the
unit’s total tons of NOX emissions
during the immediately preceding
control period.
(ii) The Administrator will adjust the
allocation amount in paragraph (a)(4)(i)
in accordance with paragraphs (a)(5)
through (7) and (12) of this section.
(5) The Administrator will calculate
the sum of the TR NOX Ozone Season
allowances determined for all such TR
NOX Ozone Season units under
paragraph (a)(4)(i) of this section in the
State for such control period.
(6) If the amount of TR NOX Ozone
Season allowances in the new unit setaside for the State for such control
period is greater than or equal to the
sum under paragraph (a)(5) of this
section, then the Administrator will
allocate the amount of TR NOX Ozone
Season allowances determined for each
such TR NOX Ozone Season unit under
paragraph (a)(4)(i) of this section.
(7) If the amount of TR NOX Ozone
Season allowances in the new unit setaside for the State for such control
period is less than the sum under
paragraph (a)(5) of this section, then the
Administrator will allocate to each such
TR NOX Ozone Season unit the amount
of the TR NOX Ozone Season
allowances determined under paragraph
(a)(4)(i) of this section for the unit,
multiplied by the amount of TR NOX
Ozone Season allowances in the new
unit set-aside for such control period,
divided by the sum under paragraph
(a)(5) of this section, and rounded to the
nearest allowance.
(8) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.511(b)(1)(i) and (ii), of the amount
of TR NOX Ozone Season allowances
allocated under paragraphs (a)(2)
through (7) and (12) of this section for
such control period to each TR NOX
Ozone Season unit eligible for such
allocation.
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(9) If, after completion of the
procedures under paragraphs (a)(5)
through (8) of this section for such
control period, any unallocated TR NOX
Ozone Season allowances remain in the
new unit set-aside for the State for such
control period, the Administrator will
allocate such TR NOX Ozone Season
allowances as follows—
(i) The Administrator will determine,
for each unit described in paragraph
(a)(1) of this section that commenced
commercial operation during the period
starting May 1 of the year before the
year of such control period and ending
August 31 of year of such control
period, the positive difference (if any)
between the unit’s emissions during
such control period and the amount of
TR NOX Ozone Season allowances
referenced in the notice of data
availability required under
§ 97.511(b)(1)(ii) for the unit for such
control period;
(ii) The Administrator will determine
the sum of the positive differences
determined under paragraph (a)(9)(i) of
this section;
(iii) If the amount of unallocated TR
NOX Ozone Season allowances
remaining in the new unit set-aside for
the State for such control period is
greater than or equal to the sum
determined under paragraph (a)(9)(ii) of
this section, then the Administrator will
allocate the amount of TR NOX Ozone
Season allowances determined for each
such TR NOX Ozone Season unit under
paragraph (a)(9)(i) of this section; and
(iv) If the amount of unallocated TR
NOX Ozone Season allowances
remaining in the new unit set-aside for
the State for such control period is less
than the sum under paragraph (a)(9)(ii)
of this section, then the Administrator
will allocate to each such TR NOX
Ozone Season unit the amount of the TR
NOX Ozone Season allowances
determined under paragraph (a)(9)(i) of
this section for the unit, multiplied by
the amount of unallocated TR NOX
Ozone Season allowances remaining in
the new unit set-aside for such control
period, divided by the sum under
paragraph (a)(9)(ii) of this section, and
rounded to the nearest allowance.
(10) If, after completion of the
procedures under paragraphs (a)(9) and
(12) of this section for such control
period, any unallocated TR NOX Ozone
Season allowances remain in the new
unit set-aside for the State for such
control period, the Administrator will
allocate to each TR NOX Ozone Season
unit that is in the State, is allocated an
amount of TR NOX Ozone Season
allowances in the notice of data
availability issued under § 97.511(a)(1),
and continues to be allocated TR NOX
PO 00000
Frm 00212
Fmt 4701
Sfmt 4700
Ozone Season allowances for such
control period in accordance with
§ 97.511(a)(2), an amount of TR NOX
Ozone Season allowances equal to the
following: the total amount of such
remaining unallocated TR NOX Ozone
Season allowances in such new unit setaside, multiplied by the unit’s allocation
under § 97.511(a) for such control
period, divided by the remainder of the
amount of tons in the applicable State
NOX Ozone Season trading budget
minus the sum of the amounts of tons
in such new unit set-aside and the
Indian country new unit set-aside for
the State for such control period, and
rounded to the nearest allowance.
(11) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.511(b)(1)(iii), (iv), and (v), of the
amount of TR NOX Ozone Season
allowances allocated under paragraphs
(a)(9), (10), and (12) of this section for
such control period to each TR NOX
Ozone Season unit eligible for such
allocation.
(12)(i) Notwithstanding the
requirements of paragraphs (a)(2)
through (11) of this section, if the
calculations of allocations of a new unit
set-aside for a control period in a given
year under paragraph (a)(7) of this
section, paragraphs (a)(6) and (9)(iv) of
this section, or paragraphs (a)(6), (9)(iii),
and (10) of this section would otherwise
result in total allocations of such new
unit set-aside exceeding the total
amount of such new unit set-aside, then
the Administrator will adjust the results
of the calculations under paragraph
(a)(7), (9)(iv), or (10) of this section, as
applicable, as follows. The
Administrator will list the TR NOX
Ozone Season units in descending order
based on the amount of such units’
allocations under paragraph (a)(7),
(9)(iv), or (10) of this section, as
applicable, and, in cases of equal
allocation amounts, in alphabetical
order of the relevant source’s name and
numerical order of the relevant unit’s
identification number, and will reduce
each unit’s allocation under paragraph
(a)(7), (9)(iv), or (10) of this section, as
applicable, by one TR NOX Ozone
Season allowance (but not below zero)
in the order in which the units are listed
and will repeat this reduction process as
necessary, until the total allocations of
such new unit set-aside equal the total
amount of such new unit set-aside.
(ii) Notwithstanding the requirements
of paragraphs (a)(10) and (11) of this
section, if the calculations of allocations
of a new unit set-aside for a control
period in a given year under paragraphs
(a)(6), (9)(iii), and (10) of this section
would otherwise result in a total
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allocations of such new unit set-aside
less than the total amount of such new
unit set-aside, then the Administrator
will adjust the results of the calculations
under paragraph (a)(10) of this section,
as follows. The Administrator will list
the TR NOX Ozone Season units in
descending order based on the amount
of such units’ allocations under
paragraph (a)(10) of this section and, in
cases of equal allocation amounts, in
alphabetical order of the relevant
source’s name and numerical order of
the relevant unit’s identification
number, and will increase each unit’s
allocation under paragraph (a)(10) of
this section by one TR NOX Ozone
Season allowance in the order in which
the units are listed and will repeat this
increase process as necessary, until the
total allocations of such new unit setaside equal the total amount of such
new unit set-aside.
(b) For each control period in 2012
and thereafter and for the TR NOX
Ozone Season units located in Indian
country within the borders of each
State, the Administrator will allocate TR
NOX Ozone Season allowances to the
TR NOX Ozone Season units as follows:
(1) The TR NOX Ozone Season
allowances will be allocated to the
following TR NOX Ozone Season units,
except as provided in paragraph (b)(10)
of this section:
(i) TR NOX Ozone Season units that
are not allocated an amount of TR NOX
Ozone Season allowances in the notice
of data availability issued under
§ 97.511(a)(1); or
(ii) For purposes of paragraph (b)(9) of
this section, TR NOX Ozone Season
units under § 97.511(c)(1)(ii) whose
allocation of an amount of TR NOX
Ozone Season allowances for such
control period in the notice of data
availability issued under
§ 97.511(b)(2)(ii)(B) is covered by
§ 97.511(c)(2) or (3).
(2) The Administrator will establish a
separate Indian country new unit setaside for the State for each such control
period. Each such Indian country new
unit set-aside will be allocated TR NOX
Ozone Season allowances in an amount
equal to the applicable amount of tons
of NOX emissions as set forth in
§ 97.510(a) and will be allocated
additional TR NOX Ozone Season
allowances (if any) in accordance with
§ 97.511(c)(5).
(3) The Administrator will determine,
for each TR NOX Ozone Season unit
described in paragraph (b)(1) of this
section, an allocation of TR NOX Ozone
Season allowances for the later of the
following control periods and for each
subsequent control period:
(i) The control period in 2012; and
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Jkt 223001
(ii) The first control period after the
control period in which the TR NOX
Ozone Season unit commences
commercial operation.
(4)(i) The allocation to each TR NOX
Ozone Season unit described in
paragraph (b)(1)(i) of this section and for
each control period described in
paragraph (b)(3) of this section will be
an amount equal to the unit’s total tons
of NOX emissions during the
immediately preceding control period.
(ii) The Administrator will adjust the
allocation amount in paragraph (b)(4)(i)
in accordance with paragraphs (b)(5)
through (7) and (12) of this section.
(5) The Administrator will calculate
the sum of the TR NOX Ozone Season
allowances determined for all such TR
NOX Ozone Season units under
paragraph (b)(4)(i) of this section in
Indian country within the borders of the
State for such control period.
(6) If the amount of TR NOX Ozone
Season allowances in the Indian country
new unit set-aside for the State for such
control period is greater than or equal to
the sum under paragraph (b)(5) of this
section, then the Administrator will
allocate the amount of TR NOX Ozone
Season allowances determined for each
such TR NOX Ozone Season unit under
paragraph (b)(4)(i) of this section.
(7) If the amount of TR NOX Ozone
Season allowances in the Indian country
new unit set-aside for the State for such
control period is less than the sum
under paragraph (b)(5) of this section,
then the Administrator will allocate to
each such TR NOX Ozone Season unit
the amount of the TR NOX Ozone
Season allowances determined under
paragraph (b)(4)(i) of this section for the
unit, multiplied by the amount of TR
NOX Ozone Season allowances in the
Indian country new unit set-aside for
such control period, divided by the sum
under paragraph (b)(5) of this section,
and rounded to the nearest allowance.
(8) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.511(b)(2)(i) and (ii), of the amount
of TR NOX Ozone Season allowances
allocated under paragraphs (b)(2)
through (7) and (12) of this section for
such control period to each TR NOX
Ozone Season unit eligible for such
allocation.
(9) If, after completion of the
procedures under paragraphs (b)(5)
through (8) of this section for such
control period, any unallocated TR NOX
Ozone Season allowances remain in the
Indian country new unit set-aside for
the State for such control period, the
Administrator will allocate such TR
NOX Ozone Season allowances as
follows—
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48419
(i) The Administrator will determine,
for each unit described in paragraph
(b)(1) of this section that commenced
commercial operation during the period
starting May 1 of the year before the
year of such control period and ending
August 31 of year of such control
period, the positive difference (if any)
between the unit’s emissions during
such control period and the amount of
TR NOX Ozone Season allowances
referenced in the notice of data
availability required under
§ 97.511(b)(2)(ii) for the unit for such
control period;
(ii) The Administrator will determine
the sum of the positive differences
determined under paragraph (b)(9)(i) of
this section;
(iii) If the amount of unallocated TR
NOX Ozone Season allowances
remaining in the Indian country new
unit set-aside for the State for such
control period is greater than or equal to
the sum determined under paragraph
(b)(9)(ii) of this section, then the
Administrator will allocate the amount
of TR NOX Ozone Season allowances
determined for each such TR NOX
Ozone Season unit under paragraph
(b)(9)(i) of this section; and
(iv) If the amount of unallocated TR
NOX Ozone Season allowances
remaining in the Indian country new
unit set-aside for the State for such
control period is less than the sum
under paragraph (b)(9)(ii) of this section,
then the Administrator will allocate to
each such TR NOX Ozone Season unit
the amount of the TR NOX Ozone
Season allowances determined under
paragraph (b)(9)(i) of this section for the
unit, multiplied by the amount of
unallocated TR NOX Ozone Season
allowances remaining in the Indian
country new unit set-aside for such
control period, divided by the sum
under paragraph (b)(9)(ii) of this section,
and rounded to the nearest allowance.
(10) If, after completion of the
procedures under paragraphs (b)(9) and
(12) of this section for such control
period, any unallocated TR NOX Ozone
Season allowances remain in the Indian
country new unit set-aside for the State
for such control period, the
Administrator will:
(i) Transfer such unallocated TR NOX
Ozone Season allowances to the new
unit set-aside for the State for such
control period; or
(ii) If the State has a SIP revision
approved under § 52.38(b)(4) or (5)
covering such control period, include
such unallocated TR NOX Ozone Season
allowances in the portion of the State
NOX Ozone Season trading budget that
may be allocated for such control period
in accordance with such SIP revision.
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(11) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.511(b)(2)(iii), (iv), and (v), of the
amount of TR NOX Ozone Season
allowances allocated under paragraphs
(b)(9), (10), and (12) of this section for
such control period to each TR NOX
Ozone Season unit eligible for such
allocation.
(12)(i) Notwithstanding the
requirements of paragraphs (b)(2)
through (11) of this section, if the
calculations of allocations of an Indian
country new unit set-aside for a control
period in a given year under paragraph
(b)(7) of this section, paragraphs (b)(6)
and (9)(iv) of this section, or paragraphs
(b)(6), (9)(iii), and (10) of this section
would otherwise result in total
allocations of such Indian country new
unit set-aside exceeding the total
amount of such Indian country new unit
set-aside, then the Administrator will
adjust the results of the calculations
under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, as follows.
The Administrator will list the TR NOX
Ozone Season units in descending order
based on the amount of such units’
allocations under paragraph (b)(7),
(9)(iv), or (10) of this section, as
applicable, and, in cases of equal
allocation amounts, in alphabetical
order of the relevant source’s name and
numerical order of the relevant unit’s
identification number, and will reduce
each unit’s allocation under paragraph
(b)(7), (9)(iv), or (10) of this section, as
applicable, by one TR NOX Ozone
Season allowance (but not below zero)
in the order in which the units are listed
and will repeat this reduction process as
necessary, until the total allocations of
such Indian country new unit set-aside
equal the total amount of such Indian
country new unit set-aside.
(ii) Notwithstanding the requirements
of paragraphs (b)(10) and (11) of this
section, if the calculations of allocations
of an Indian country new unit set-aside
for a control period in a given year
under paragraphs (b)(6), (9)(iii), and (10)
of this section would otherwise result in
a total allocations of such Indian
country new unit set-aside less than the
total amount of such Indian country
new unit set-aside, then the
Administrator will adjust the results of
the calculations under paragraph (b)(10)
of this section, as follows. The
Administrator will list the TR NOX
Ozone Season units in descending order
based on the amount of such units’
allocations under paragraph (b)(10) of
this section and, in cases of equal
allocation amounts, in alphabetical
order of the relevant source’s name and
numerical order of the relevant unit’s
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identification number, and will increase
each unit’s allocation under paragraph
(b)(10) of this section by one TR NOX
Ozone Season allowance in the order in
which the units are listed and will
repeat this increase process as
necessary, until the total allocations of
such Indian country new unit set-aside
equal the total amount of such Indian
country new unit set-aside.
§ 97.513 Authorization of designated
representative and alternate designated
representative.
(a) Except as provided under § 97.515,
each TR NOX Ozone Season source,
including all TR NOX Ozone Season
units at the source, shall have one and
only one designated representative, with
regard to all matters under the TR NOX
Ozone Season Trading Program.
(1) The designated representative
shall be selected by an agreement
binding on the owners and operators of
the source and all TR NOX Ozone
Season units at the source and shall act
in accordance with the certification
statement in § 97.516(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 97.516:
(i) The designated representative shall
be authorized and shall represent and,
by his or her representations, actions,
inactions, or submissions, legally bind
each owner and operator of the source
and each TR NOX Ozone Season unit at
the source in all matters pertaining to
the TR NOX Ozone Season Trading
Program, notwithstanding any
agreement between the designated
representative and such owners and
operators; and
(ii) The owners and operators of the
source and each TR NOX Ozone Season
unit at the source shall be bound by any
decision or order issued to the
designated representative by the
Administrator regarding the source or
any such unit.
(b) Except as provided under § 97.515,
each TR NOX Ozone Season source may
have one and only one alternate
designated representative, who may act
on behalf of the designated
representative. The agreement by which
the alternate designated representative
is selected shall include a procedure for
authorizing the alternate designated
representative to act in lieu of the
designated representative.
(1) The alternate designated
representative shall be selected by an
agreement binding on the owners and
operators of the source and all TR NOX
Ozone Season units at the source and
shall act in accordance with the
certification statement in
§ 97.516(a)(4)(iii).
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(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 97.516,
(i) The alternate designated
representative shall be authorized;
(ii) Any representation, action,
inaction, or submission by the alternate
designated representative shall be
deemed to be a representation, action,
inaction, or submission by the
designated representative; and
(iii) The owners and operators of the
source and each TR NOX Ozone Season
unit at the source shall be bound by any
decision or order issued to the alternate
designated representative by the
Administrator regarding the source or
any such unit.
(c) Except in this section, § 97.502,
and §§ 97.514 through 97.518, whenever
the term ‘‘designated representative’’ (as
distinguished from the term ‘‘common
designated representative’’) is used in
this subpart, the term shall be construed
to include the designated representative
or any alternate designated
representative.
§ 97.514 Responsibilities of designated
representative and alternate designated
representative.
(a) Except as provided under § 97.518
concerning delegation of authority to
make submissions, each submission
under the TR NOX Ozone Season
Trading Program shall be made, signed,
and certified by the designated
representative or alternate designated
representative for each TR NOX Ozone
Season source and TR NOX Ozone
Season unit for which the submission is
made. Each such submission shall
include the following certification
statement by the designated
representative or alternate designated
representative: ‘‘I am authorized to
make this submission on behalf of the
owners and operators of the source or
units for which the submission is made.
I certify under penalty of law that I have
personally examined, and am familiar
with, the statements and information
submitted in this document and all its
attachments. Based on my inquiry of
those individuals with primary
responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(b) The Administrator will accept or
act on a submission made for a TR NOX
Ozone Season source or a TR NOX
Ozone Season unit only if the
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submission has been made, signed, and
certified in accordance with paragraph
(a) of this section and § 97.518.
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§ 97.515 Changing designated
representative and alternate designated
representative; changes in owners and
operators; changes in units at the source.
(a) Changing designated
representative. The designated
representative may be changed at any
time upon receipt by the Administrator
of a superseding complete certificate of
representation under § 97.516.
Notwithstanding any such change, all
representations, actions, inactions, and
submissions by the previous designated
representative before the time and date
when the Administrator receives the
superseding certificate of representation
shall be binding on the new designated
representative and the owners and
operators of the TR NOX Ozone Season
source and the TR NOX Ozone Season
units at the source.
(b) Changing alternate designated
representative. The alternate designated
representative may be changed at any
time upon receipt by the Administrator
of a superseding complete certificate of
representation under § 97.516.
Notwithstanding any such change, all
representations, actions, inactions, and
submissions by the previous alternate
designated representative before the
time and date when the Administrator
receives the superseding certificate of
representation shall be binding on the
new alternate designated representative,
the designated representative, and the
owners and operators of the TR NOX
Ozone Season source and the TR NOX
Ozone Season units at the source.
(c) Changes in owners and operators.
(1) In the event an owner or operator of
a TR NOX Ozone Season source or a TR
NOX Ozone Season unit at the source is
not included in the list of owners and
operators in the certificate of
representation under § 97.516, such
owner or operator shall be deemed to be
subject to and bound by the certificate
of representation, the representations,
actions, inactions, and submissions of
the designated representative and any
alternate designated representative of
the source or unit, and the decisions
and orders of the Administrator, as if
the owner or operator were included in
such list.
(2) Within 30 days after any change in
the owners and operators of a TR NOX
Ozone Season source or a TR NOX
Ozone Season unit at the source,
including the addition or removal of an
owner or operator, the designated
representative or any alternate
designated representative shall submit a
revision to the certificate of
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representation under § 97.516 amending
the list of owners and operators to
reflect the change.
(d) Changes in units at the source.
Within 30 days of any change in which
units are located at a TR NOX Ozone
Season source (including the addition or
removal of a unit), the designated
representative or any alternate
designated representative shall submit a
certificate of representation under
§ 97.516 amending the list of units to
reflect the change.
(1) If the change is the addition of a
unit that operated (other than for
purposes of testing by the manufacturer
before initial installation) before being
located at the source, then the certificate
of representation shall identify, in a
format prescribed by the Administrator,
the entity from whom the unit was
purchased or otherwise obtained
(including name, address, telephone
number, and facsimile number (if any)),
the date on which the unit was
purchased or otherwise obtained, and
the date on which the unit became
located at the source.
(2) If the change is the removal of a
unit, then the certificate of
representation shall identify, in a format
prescribed by the Administrator, the
entity to which the unit was sold or that
otherwise obtained the unit (including
name, address, telephone number, and
facsimile number (if any)), the date on
which the unit was sold or otherwise
obtained, and the date on which the
unit became no longer located at the
source.
§ 97.516
Certificate of representation.
(a) A complete certificate of
representation for a designated
representative or an alternate designated
representative shall include the
following elements in a format
prescribed by the Administrator:
(1) Identification of the TR NOX
Ozone Season source, and each TR NOX
Ozone Season unit at the source, for
which the certificate of representation is
submitted, including source name,
source category and NAICS code (or, in
the absence of a NAICS code, an
equivalent code), State, plant code,
county, latitude and longitude, unit
identification number and type,
identification number and nameplate
capacity (in MWe, rounded to the
nearest tenth) of each generator served
by each such unit, actual or projected
date of commencement of commercial
operation, and a statement of whether
such source is located in Indian
Country. If a projected date of
commencement of commercial
operation is provided, the actual date of
commencement of commercial
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48421
operation shall be provided when such
information becomes available.
(2) The name, address, e-mail address
(if any), telephone number, and
facsimile transmission number (if any)
of the designated representative and any
alternate designated representative.
(3) A list of the owners and operators
of the TR NOX Ozone Season source and
of each TR NOX Ozone Season unit at
the source.
(4) The following certification
statements by the designated
representative and any alternate
designated representative—
(i) ‘‘I certify that I was selected as the
designated representative or alternate
designated representative, as applicable,
by an agreement binding on the owners
and operators of the source and each TR
NOX Ozone Season unit at the source.’’
(ii) ‘‘I certify that I have all the
necessary authority to carry out my
duties and responsibilities under the TR
NOX Ozone Season Trading Program on
behalf of the owners and operators of
the source and of each TR NOX Ozone
Season unit at the source and that each
such owner and operator shall be fully
bound by my representations, actions,
inactions, or submissions and by any
decision or order issued to me by the
Administrator regarding the source or
unit.’’
(iii) ‘‘Where there are multiple
holders of a legal or equitable title to, or
a leasehold interest in, a TR NOX Ozone
Season unit, or where a utility or
industrial customer purchases power
from a TR NOX Ozone Season unit
under a life-of-the-unit, firm power
contractual arrangement, I certify that: I
have given a written notice of my
selection as the ‘designated
representative’ or ‘alternate designated
representative’, as applicable, and of the
agreement by which I was selected to
each owner and operator of the source
and of each TR NOX Ozone Season unit
at the source; and TR NOX Ozone
Season allowances and proceeds of
transactions involving TR NOX Ozone
Season allowances will be deemed to be
held or distributed in proportion to each
holder’s legal, equitable, leasehold, or
contractual reservation or entitlement,
except that, if such multiple holders
have expressly provided for a different
distribution of TR NOX Ozone Season
allowances by contract, TR NOX Ozone
Season allowances and proceeds of
transactions involving TR NOX Ozone
Season allowances will be deemed to be
held or distributed in accordance with
the contract.’’
(5) The signature of the designated
representative and any alternate
designated representative and the dates
signed.
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(b) Unless otherwise required by the
Administrator, documents of agreement
referred to in the certificate of
representation shall not be submitted to
the Administrator. The Administrator
shall not be under any obligation to
review or evaluate the sufficiency of
such documents, if submitted.
§ 97.517 Objections concerning
designated representative and alternate
designated representative.
(a) Once a complete certificate of
representation under § 97.516 has been
submitted and received, the
Administrator will rely on the certificate
of representation unless and until a
superseding complete certificate of
representation under § 97.516 is
received by the Administrator.
(b) Except as provided in paragraph
(a) of this section, no objection or other
communication submitted to the
Administrator concerning the
authorization, or any representation,
action, inaction, or submission, of a
designated representative or alternate
designated representative shall affect
any representation, action, inaction, or
submission of the designated
representative or alternate designated
representative or the finality of any
decision or order by the Administrator
under the TR NOX Ozone Season
Trading Program.
(c) The Administrator will not
adjudicate any private legal dispute
concerning the authorization or any
representation, action, inaction, or
submission of any designated
representative or alternate designated
representative, including private legal
disputes concerning the proceeds of TR
NOX Ozone Season allowance transfers.
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§ 97.518 Delegation by designated
representative and alternate designated
representative.
(a) A designated representative may
delegate, to one or more natural persons,
his or her authority to make an
electronic submission to the
Administrator provided for or required
under this subpart.
(b) An alternate designated
representative may delegate, to one or
more natural persons, his or her
authority to make an electronic
submission to the Administrator
provided for or required under this
subpart.
(c) In order to delegate authority to a
natural person to make an electronic
submission to the Administrator in
accordance with paragraph (a) or (b) of
this section, the designated
representative or alternate designated
representative, as appropriate, must
submit to the Administrator a notice of
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delegation, in a format prescribed by the
Administrator, that includes the
following elements:
(1) The name, address, e-mail address,
telephone number, and facsimile
transmission number (if any) of such
designated representative or alternate
designated representative;
(2) The name, address, e-mail address,
telephone number, and facsimile
transmission number (if any) of each
such natural person (referred to in this
section as an ‘‘agent’’);
(3) For each such natural person, a list
of the type or types of electronic
submissions under paragraph (a) or (b)
of this section for which authority is
delegated to him or her; and
(4) The following certification
statements by such designated
representative or alternate designated
representative:
(i) ‘‘I agree that any electronic
submission to the Administrator that is
made by an agent identified in this
notice of delegation and of a type listed
for such agent in this notice of
delegation and that is made when I am
a designated representative or alternate
designated representative, as
appropriate, and before this notice of
delegation is superseded by another
notice of delegation under 40 CFR
97.518(d) shall be deemed to be an
electronic submission by me.’’
(ii) ‘‘Until this notice of delegation is
superseded by another notice of
delegation under 40 CFR 97.518(d), I
agree to maintain an e-mail account and
to notify the Administrator immediately
of any change in my e-mail address
unless all delegation of authority by me
under 40 CFR 97.518 is terminated.’’.
(d) A notice of delegation submitted
under paragraph (c) of this section shall
be effective, with regard to the
designated representative or alternate
designated representative identified in
such notice, upon receipt of such notice
by the Administrator and until receipt
by the Administrator of a superseding
notice of delegation submitted by such
designated representative or alternate
designated representative, as
appropriate. The superseding notice of
delegation may replace any previously
identified agent, add a new agent, or
eliminate entirely any delegation of
authority.
(e) Any electronic submission covered
by the certification in paragraph (c)(4)(i)
of this section and made in accordance
with a notice of delegation effective
under paragraph (d) of this section shall
be deemed to be an electronic
submission by the designated
representative or alternate designated
representative submitting such notice of
delegation.
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§ 97.519
[Reserved]
§ 97.520 Establishment of compliance
accounts, assurance accounts, and general
accounts.
(a) Compliance accounts. Upon
receipt of a complete certificate of
representation under § 97.516, the
Administrator will establish a
compliance account for the TR NOX
Ozone Season source for which the
certificate of representation was
submitted, unless the source already has
a compliance account. The designated
representative and any alternate
designated representative of the source
shall be the authorized account
representative and the alternate
authorized account representative
respectively of the compliance account.
(b) Assurance accounts. The
Administrator will establish assurance
accounts for certain owners and
operators and States in accordance with
§ 97.525(b)(3).
(c) General accounts. (1) Application
for general account. (i) Any person may
apply to open a general account, for the
purpose of holding and transferring TR
NOX Ozone Season allowances, by
submitting to the Administrator a
complete application for a general
account. Such application shall
designate one and only one authorized
account representative and may
designate one and only one alternate
authorized account representative who
may act on behalf of the authorized
account representative.
(A) The authorized account
representative and alternate authorized
account representative shall be selected
by an agreement binding on the persons
who have an ownership interest with
respect to TR NOX Ozone Season
allowances held in the general account.
(B) The agreement by which the
alternate authorized account
representative is selected shall include
a procedure for authorizing the alternate
authorized account representative to act
in lieu of the authorized account
representative.
(ii) A complete application for a
general account shall include the
following elements in a format
prescribed by the Administrator:
(A) Name, mailing address, e-mail
address (if any), telephone number, and
facsimile transmission number (if any)
of the authorized account representative
and any alternate authorized account
representative;
(B) An identifying name for the
general account;
(C) A list of all persons subject to a
binding agreement for the authorized
account representative and any alternate
authorized account representative to
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represent their ownership interest with
respect to the TR NOX Ozone Season
allowances held in the general account;
(D) The following certification
statement by the authorized account
representative and any alternate
authorized account representative: ‘‘I
certify that I was selected as the
authorized account representative or the
alternate authorized account
representative, as applicable, by an
agreement that is binding on all persons
who have an ownership interest with
respect to TR NOX Ozone Season
allowances held in the general account.
I certify that I have all the necessary
authority to carry out my duties and
responsibilities under the TR NOX
Ozone Season Trading Program on
behalf of such persons and that each
such person shall be fully bound by my
representations, actions, inactions, or
submissions and by any decision or
order issued to me by the Administrator
regarding the general account.’’
(E) The signature of the authorized
account representative and any alternate
authorized account representative and
the dates signed.
(iii) Unless otherwise required by the
Administrator, documents of agreement
referred to in the application for a
general account shall not be submitted
to the Administrator. The Administrator
shall not be under any obligation to
review or evaluate the sufficiency of
such documents, if submitted.
(2) Authorization of authorized
account representative and alternate
authorized account representative. (i)
Upon receipt by the Administrator of a
complete application for a general
account under paragraph (b)(1) of this
section, the Administrator will establish
a general account for the person or
persons for whom the application is
submitted, and upon and after such
receipt by the Administrator:
(A) The authorized account
representative of the general account
shall be authorized and shall represent
and, by his or her representations,
actions, inactions, or submissions,
legally bind each person who has an
ownership interest with respect to TR
NOX Ozone Season allowances held in
the general account in all matters
pertaining to the TR NOX Ozone Season
Trading Program, notwithstanding any
agreement between the authorized
account representative and such person.
(B) Any alternate authorized account
representative shall be authorized, and
any representation, action, inaction, or
submission by any alternate authorized
account representative shall be deemed
to be a representation, action, inaction,
or submission by the authorized account
representative.
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(C) Each person who has an
ownership interest with respect to TR
NOX Ozone Season allowances held in
the general account shall be bound by
any decision or order issued to the
authorized account representative or
alternate authorized account
representative by the Administrator
regarding the general account.
(ii) Except as provided in paragraph
(c)(5) of this section concerning
delegation of authority to make
submissions, each submission
concerning the general account shall be
made, signed, and certified by the
authorized account representative or
any alternate authorized account
representative for the persons having an
ownership interest with respect to TR
NOX Ozone Season allowances held in
the general account. Each such
submission shall include the following
certification statement by the authorized
account representative or any alternate
authorized account representative: ‘‘I
am authorized to make this submission
on behalf of the persons having an
ownership interest with respect to the
TR NOX Ozone Season allowances held
in the general account. I certify under
penalty of law that I have personally
examined, and am familiar with, the
statements and information submitted
in this document and all its
attachments. Based on my inquiry of
those individuals with primary
responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(iii) Except in this section, whenever
the term ‘‘authorized account
representative’’ is used in this subpart,
the term shall be construed to include
the authorized account representative or
any alternate authorized account
representative.
(3) Changing authorized account
representative and alternate authorized
account representative; changes in
persons with ownership interest. (i) The
authorized account representative of a
general account may be changed at any
time upon receipt by the Administrator
of a superseding complete application
for a general account under paragraph
(c)(1) of this section. Notwithstanding
any such change, all representations,
actions, inactions, and submissions by
the previous authorized account
representative before the time and date
when the Administrator receives the
superseding application for a general
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48423
account shall be binding on the new
authorized account representative and
the persons with an ownership interest
with respect to the TR NOX Ozone
Season allowances in the general
account.
(ii) The alternate authorized account
representative of a general account may
be changed at any time upon receipt by
the Administrator of a superseding
complete application for a general
account under paragraph (c)(1) of this
section. Notwithstanding any such
change, all representations, actions,
inactions, and submissions by the
previous alternate authorized account
representative before the time and date
when the Administrator receives the
superseding application for a general
account shall be binding on the new
alternate authorized account
representative, the authorized account
representative, and the persons with an
ownership interest with respect to the
TR NOX Ozone Season allowances in
the general account.
(iii)(A) In the event a person having
an ownership interest with respect to
TR NOX Ozone Season allowances in
the general account is not included in
the list of such persons in the
application for a general account, such
person shall be deemed to be subject to
and bound by the application for a
general account, the representation,
actions, inactions, and submissions of
the authorized account representative
and any alternate authorized account
representative of the account, and the
decisions and orders of the
Administrator, as if the person were
included in such list.
(B) Within 30 days after any change
in the persons having an ownership
interest with respect to NOX Ozone
Season allowances in the general
account, including the addition or
removal of a person, the authorized
account representative or any alternate
authorized account representative shall
submit a revision to the application for
a general account amending the list of
persons having an ownership interest
with respect to the TR NOX Ozone
Season allowances in the general
account to include the change.
(4) Objections concerning authorized
account representative and alternate
authorized account representative. (i)
Once a complete application for a
general account under paragraph (c)(1)
of this section has been submitted and
received, the Administrator will rely on
the application unless and until a
superseding complete application for a
general account under paragraph (b)(1)
of this section is received by the
Administrator.
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(ii) Except as provided in paragraph
(c)(4)(i) of this section, no objection or
other communication submitted to the
Administrator concerning the
authorization, or any representation,
action, inaction, or submission of the
authorized account representative or
any alternate authorized account
representative of a general account shall
affect any representation, action,
inaction, or submission of the
authorized account representative or
any alternate authorized account
representative or the finality of any
decision or order by the Administrator
under the TR NOX Ozone Season
Trading Program.
(iii) The Administrator will not
adjudicate any private legal dispute
concerning the authorization or any
representation, action, inaction, or
submission of the authorized account
representative or any alternate
authorized account representative of a
general account, including private legal
disputes concerning the proceeds of TR
NOX Ozone Season allowance transfers.
(5) Delegation by authorized account
representative and alternate authorized
account representative. (i) An
authorized account representative of a
general account may delegate, to one or
more natural persons, his or her
authority to make an electronic
submission to the Administrator
provided for or required under this
subpart.
(ii) An alternate authorized account
representative of a general account may
delegate, to one or more natural persons,
his or her authority to make an
electronic submission to the
Administrator provided for or required
under this subpart.
(iii) In order to delegate authority to
a natural person to make an electronic
submission to the Administrator in
accordance with paragraph (c)(5)(i) or
(ii) of this section, the authorized
account representative or alternate
authorized account representative, as
appropriate, must submit to the
Administrator a notice of delegation, in
a format prescribed by the
Administrator, that includes the
following elements:
(A) The name, address, e-mail
address, telephone number, and
facsimile transmission number (if any)
of such authorized account
representative or alternate authorized
account representative;
(B) The name, address, e-mail
address, telephone number, and
facsimile transmission number (if any)
of each such natural person (referred to
in this section as an ‘‘agent’’);
(C) For each such natural person, a
list of the type or types of electronic
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submissions under paragraph (c)(5)(i) or
(ii) of this section for which authority is
delegated to him or her;
(D) The following certification
statement by such authorized account
representative or alternate authorized
account representative: ‘‘I agree that any
electronic submission to the
Administrator that is made by an agent
identified in this notice of delegation
and of a type listed for such agent in
this notice of delegation and that is
made when I am an authorized account
representative or alternate authorized
representative, as appropriate, and
before this notice of delegation is
superseded by another notice of
delegation under 40 CFR 97.520(c)(5)(iv)
shall be deemed to be an electronic
submission by me.’’; and
(E) The following certification
statement by such authorized account
representative or alternate authorized
account representative: ‘‘Until this
notice of delegation is superseded by
another notice of delegation under 40
CFR 97.520(c)(5)(iv), I agree to maintain
an e-mail account and to notify the
Administrator immediately of any
change in my e-mail address unless all
delegation of authority by me under 40
CFR 97.520(c)(5) is terminated.’’.
(iv) A notice of delegation submitted
under paragraph (c)(5)(iii) of this section
shall be effective, with regard to the
authorized account representative or
alternate authorized account
representative identified in such notice,
upon receipt of such notice by the
Administrator and until receipt by the
Administrator of a superseding notice of
delegation submitted by such
authorized account representative or
alternate authorized account
representative, as appropriate. The
superseding notice of delegation may
replace any previously identified agent,
add a new agent, or eliminate entirely
any delegation of authority.
(v) Any electronic submission covered
by the certification in paragraph
(c)(5)(iii)(D) of this section and made in
accordance with a notice of delegation
effective under paragraph (c)(5)(iv) of
this section shall be deemed to be an
electronic submission by the designated
representative or alternate designated
representative submitting such notice of
delegation.
(6) Closing a general account. (i) The
authorized account representative or
alternate authorized account
representative of a general account may
submit to the Administrator a request to
close the account. Such request shall
include a correctly submitted TR NOX
Ozone Season allowance transfer under
§ 97.522 for any TR NOX Ozone Season
allowances in the account to one or
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more other Allowance Management
System accounts.
(ii) If a general account has no TR
NOX Ozone Season allowance transfers
to or from the account for a 12-month
period or longer and does not contain
any TR NOX Ozone Season allowances,
the Administrator may notify the
authorized account representative for
the account that the account will be
closed after 30 days after the notice is
sent. The account will be closed after
the 30-day period unless, before the end
of the 30-day period, the Administrator
receives a correctly submitted TR NOX
Ozone Season allowance transfer under
§ 97.522 to the account or a statement
submitted by the authorized account
representative or alternate authorized
account representative demonstrating to
the satisfaction of the Administrator
good cause as to why the account
should not be closed.
(d) Account identification. The
Administrator will assign a unique
identifying number to each account
established under paragraph (a), (b), or
(c) of this section.
(e) Responsibilities of authorized
account representative and alternate
authorized account representative. After
the establishment of a compliance
account or general account, the
Administrator will accept or act on a
submission pertaining to the account,
including, but not limited to,
submissions concerning the deduction
or transfer of TR NOX Ozone Season
allowances in the account, only if the
submission has been made, signed, and
certified in accordance with §§ 97.514(a)
and 97.518 or paragraphs (c)(2)(ii) and
(c)(5) of this section.
§ 97.521 Recordation of TR NOX Ozone
Season allowance allocations and auction
results.
(a) By November 7, 2011, the
Administrator will record in each TR
NOX Ozone Season source’s compliance
account the TR NOX Ozone Season
allowances allocated to the TR NOX
Ozone Season units at the source in
accordance with § 97.511(a) for the
control period in 2012.
(b) By November 7, 2011, the
Administrator will record in each TR
NOX Ozone Season source’s compliance
account the TR NOX Ozone Season
allowances allocated to the TR NOX
Ozone Season units at the source in
accordance with § 97.511(a) for the
control period in 2013, unless the State
in which the source is located notifies
the Administrator in writing by October
17, 2011 of the State’s intent to submit
to the Administrator a complete SIP
revision by April 1, 2012 meeting the
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requirements of § 52.38(b)(3)(i) through
(iv) of this chapter.
(1) If, by April 1, 2012, the State does
not submit to the Administrator such
complete SIP revision, the
Administrator will record by April 15,
2012 in each TR NOX Ozone Season
source’s compliance account the TR
NOX Ozone Season allowances allocated
to the TR NOX Ozone Season units at
the source in accordance with
§ 97.511(a) for the control period in
2013.
(2) If the State submits to the
Administrator by April 1, 2012, and the
Administrator approves by October 1,
2012, such complete SIP revision, the
Administrator will record by October 1,
2012 in each TR NOX Ozone Season
source’s compliance account the TR
NOX Ozone Season allowances allocated
to the TR NOX Ozone Season units at
the source as provided in such
approved, complete SIP revision for the
control period in 2013.
(3) If the State submits to the
Administrator by April 1, 2012, and the
Administrator does not approve by
October 1, 2012, such complete SIP
revision, the Administrator will record
by October 1, 2012 in each TR NOX
Ozone Season source’s compliance
account the TR NOX Ozone Season
allowances allocated to the TR NOX
Ozone Season units at the source in
accordance with § 97.511(a) for the
control period in 2013.
(c) By July 1, 2013, the Administrator
will record in each TR NOX Ozone
Season source’s compliance account the
TR NOX Ozone Season allowances
allocated to the TR NOX Ozone Season
units at the source, or in each
appropriate Allowance Management
System account the TR NOX Ozone
Season allowances auctioned to TR NOX
Ozone Season units, in accordance with
§ 97.511(a), or with a SIP revision
approved under § 52.38(b)(4) or (5) of
this chapter, for the control period in
2014 and 2015.
(d) By July 1, 2014, the Administrator
will record in each TR NOX Ozone
Season source’s compliance account the
TR NOX Ozone Season allowances
allocated to the TR NOX Ozone Season
units at the source, or in each
appropriate Allowance Management
System account the TR NOX Ozone
Season allowances auctioned to TR NOX
Ozone Season units, in accordance with
§ 97.511(a), or with a SIP revision
approved under § 52.38(b)(4) or (5) of
this chapter, for the control period in
2016 and 2017.
(e) By July 1, 2015, the Administrator
will record in each TR NOX Ozone
Season source’s compliance account the
TR NOX Ozone Season allowances
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19:20 Aug 05, 2011
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allocated to the TR NOX Ozone Season
units at the source, or in each
appropriate Allowance Management
System account the TR NOX Ozone
Season allowances auctioned to TR NOX
Ozone Season units, in accordance with
§ 97.511(a), or with a SIP revision
approved under § 52.38(b)(4) or (5) of
this chapter, for the control period in
2018 and 2019.
(f) By July 1, 2016 and July 1 of each
year thereafter, the Administrator will
record in each TR NOX Ozone Season
source’s compliance account the TR
NOX Ozone Season allowances allocated
to the TR NOX Ozone Season units at
the source, or in each appropriate
Allowance Management System account
the TR NOX Ozone Season allowances
auctioned to TR NOX Ozone Season
units, in accordance with § 97.511(a), or
with a SIP revision approved under
§ 52.38(b)(4) or (5) of this chapter, for
the control period in the fourth year
after the year of the applicable
recordation deadline under this
paragraph.
(g) By August 1, 2012 and August 1
of each year thereafter, the
Administrator will record in each TR
NOX Ozone Season source’s compliance
account the TR NOX Ozone Season
allowances allocated to the TR NOX
Ozone Season units at the source, or in
each appropriate Allowance
Management System account the TR
NOX Ozone Season allowances
auctioned to TR NOX Ozone Season
units, in accordance with § 97.512(a)(2)
through (8) and (12), or with a SIP
revision approved under § 52.38(b)(4) or
(5) of this chapter, for the control period
in the year of the applicable recordation
deadline under this paragraph.
(h) By August 1, 2012 and August 1
of each year thereafter, the
Administrator will record in each TR
NOX Ozone Season source’s compliance
account the TR NOX Ozone Season
allowances allocated to the TR NOX
Ozone Season units at the source in
accordance with § 97.512(b)(2) through
(8) and (12) for the control period in the
year of the applicable recordation
deadline under this paragraph.
(i) By November 15, 2012 and
November 15 of each year thereafter, the
Administrator will record in each TR
NOX Ozone Season source’s compliance
account the TR NOX Ozone Season
allowances allocated to the TR NOX
Ozone Season units at the source in
accordance with § 97.512(a)(9) through
(12), for the control period in the year
of the applicable recordation deadline
under this paragraph.
(j) By the date on which any
allocation or auction results, other than
an allocation or auction results
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48425
described in paragraphs (a) through (i)
of this section, of TR NOX Ozone Season
allowances to a recipient is made by or
are submitted to the Administrator in
accordance with § 97.511 or § 97.512 or
with a SIP revision approved under
§ 52.38(b)(4) or (5) of this chapter, the
Administrator will record such
allocation or auction results in the
appropriate Allowance Management
System account.
(k) When recording the allocation or
auction of TR NOX Ozone Season
allowances to a TR NOX Ozone Season
unit or other entity in an Allowance
Management System account, the
Administrator will assign each TR NOX
Ozone Season allowance a unique
identification number that will include
digits identifying the year of the control
period for which the TR NOX Ozone
Season allowance is allocated or
auctioned.
§ 97.522 Submission of TR NOX Ozone
Season allowance transfers.
(a) An authorized account
representative seeking recordation of a
TR NOX Ozone Season allowance
transfer shall submit the transfer to the
Administrator.
(b) A TR NOX Ozone Season
allowance transfer shall be correctly
submitted if:
(1) The transfer includes the following
elements, in a format prescribed by the
Administrator:
(i) The account numbers established
by the Administrator for both the
transferor and transferee accounts;
(ii) The serial number of each TR NOX
Ozone Season allowance that is in the
transferor account and is to be
transferred; and
(iii) The name and signature of the
authorized account representative of the
transferor account and the date signed;
and
(2) When the Administrator attempts
to record the transfer, the transferor
account includes each TR NOX Ozone
Season allowance identified by serial
number in the transfer.
§ 97.523 Recordation of TR NOX Ozone
Season allowance transfers.
(a) Within 5 business days (except as
provided in paragraph (b) of this
section) of receiving a TR NOX Ozone
Season allowance transfer that is
correctly submitted under § 97.522, the
Administrator will record a TR NOX
Ozone Season allowance transfer by
moving each TR NOX Ozone Season
allowance from the transferor account to
the transferee account as specified in
the transfer.
(b) A TR NOX Ozone Season
allowance transfer to or from a
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compliance account that is submitted
for recordation after the allowance
transfer deadline for a control period
and that includes any TR NOX Ozone
Season allowances allocated for any
control period before such allowance
transfer deadline will not be recorded
until after the Administrator completes
the deductions from such compliance
account under § 97.524 for the control
period immediately before such
allowance transfer deadline.
(c) Where a TR NOX Ozone Season
allowance transfer is not correctly
submitted under § 97.522, the
Administrator will not record such
transfer.
(d) Within 5 business days of
recordation of a TR NOX Ozone Season
allowance transfer under paragraphs (a)
and (b) of the section, the Administrator
will notify the authorized account
representatives of both the transferor
and transferee accounts.
(e) Within 10 business days of receipt
of a TR NOX Ozone Season allowance
transfer that is not correctly submitted
under § 97.522, the Administrator will
notify the authorized account
representatives of both accounts subject
to the transfer of:
(1) A decision not to record the
transfer, and
(2) The reasons for such nonrecordation.
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§ 97.524 Compliance with TR NOX Ozone
Season emissions limitation.
(a) Availability for deduction for
compliance. TR NOX Ozone Season
allowances are available to be deducted
for compliance with a source’s TR NOX
Ozone Season emissions limitation for a
control period in a given year only if the
TR NOX Ozone Season allowances:
(1) Were allocated for such control
period or a control period in a prior
year; and
(2) Are held in the source’s
compliance account as of the allowance
transfer deadline for such control
period.
(b) Deductions for compliance. After
the recordation, in accordance with
§ 97.523, of TR NOX Ozone Season
allowance transfers submitted by the
allowance transfer deadline for a control
period in a given year, the
Administrator will deduct from each
source’s compliance account TR NOX
Ozone Season allowances available
under paragraph (a) of this section in
order to determine whether the source
meets the TR NOX Ozone Season
emissions limitation for such control
period, as follows:
(1) Until the amount of TR NOX
Ozone Season allowances deducted
equals the number of tons of total NOX
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Jkt 223001
emissions from all TR NOX Ozone
Season units at the source for such
control period; or
(2) If there are insufficient TR NOX
Ozone Season allowances to complete
the deductions in paragraph (b)(1) of
this section, until no more TR NOX
Ozone Season allowances available
under paragraph (a) of this section
remain in the compliance account.
(c)(1) Identification of TR NOX Ozone
Season allowances by serial number.
The authorized account representative
for a source’s compliance account may
request that specific TR NOX Ozone
Season allowances, identified by serial
number, in the compliance account be
deducted for emissions or excess
emissions for a control period in a given
year in accordance with paragraph (b) or
(d) of this section. In order to be
complete, such request shall be
submitted to the Administrator by the
allowance transfer deadline for such
control period and include, in a format
prescribed by the Administrator, the
identification of the TR NOX Ozone
Season source and the appropriate serial
numbers.
(2) First-in, first-out. The
Administrator will deduct TR NOX
Ozone Season allowances under
paragraph (b) or (d) of this section from
the source’s compliance account in
accordance with a complete request
under paragraph (c)(1) of this section or,
in the absence of such request or in the
case of identification of an insufficient
amount of TR NOX Ozone Season
allowances in such request, on a first-in,
first-out accounting basis in the
following order:
(i) Any TR NOX Ozone Season
allowances that were allocated to the
units at the source and not transferred
out of the compliance account, in the
order of recordation; and then
(ii) Any TR NOX Ozone Season
allowances that were allocated to any
unit and transferred to and recorded in
the compliance account pursuant to this
subpart, in the order of recordation.
(d) Deductions for excess emissions.
After making the deductions for
compliance under paragraph (b) of this
section for a control period in a year in
which the TR NOX Ozone Season source
has excess emissions, the Administrator
will deduct from the source’s
compliance account an amount of TR
NOX Ozone Season allowances,
allocated for a control period in a prior
year or the control period in the year of
the excess emissions or in the
immediately following year, equal to
two times the number of tons of the
source’s excess emissions.
(e) Recordation of deductions. The
Administrator will record in the
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Sfmt 4700
appropriate compliance account all
deductions from such an account under
paragraphs (b) and (d) of this section.
§ 97.525 Compliance with TR NOX Ozone
Season assurance provisions.
(a) Availability for deduction. TR NOX
Ozone Season allowances are available
to be deducted for compliance with the
TR NOX Ozone Season assurance
provisions for a control period in a
given year by the owners and operators
of a group of one or more TR NOX
Ozone Season sources and units in a
State (and Indian country within the
borders of such State) only if the TR
NOX Ozone Season allowances:
(1) Were allocated for a control period
in a prior year or the control period in
the given year or in the immediately
following year; and
(2) Are held in the assurance account,
established by the Administrator for
such owners and operators of such
group of TR NOX Ozone Season sources
and units in such State (and Indian
country within the borders of such
State) under paragraph (b)(3) of this
section, as of the deadline established in
paragraph (b)(4) of this section.
(b) Deductions for compliance. The
Administrator will deduct TR NOX
Ozone Season allowances available
under paragraph (a) of this section for
compliance with the TR NOX Ozone
Season assurance provisions for a State
for a control period in a given year in
accordance with the following
procedures:
(1) By June 1, 2013 and June 1 of each
year thereafter, the Administrator will:
(i) Calculate, for each State (and
Indian country within the borders of
such State), the total NOX emissions
from all TR NOX Ozone Season units at
TR NOX Ozone Season sources in the
State (and Indian country within the
borders of such State) during the control
period in the year before the year of this
calculation deadline and the amount, if
any, by which such total NOX emissions
exceed the State assurance level as
described in § 97.506(c)(2)(iii); and
(ii) Promulgate a notice of data
availability of the results of the
calculations required in paragraph
(b)(1)(i) of this section, including
separate calculations of the NOX
emissions from each TR NOX Ozone
Season source.
(2) For each notice of data availability
required in paragraph (b)(1)(ii) of this
section and for any State (and Indian
country within the borders of such
State) identified in such notice as
having TR NOX Ozone Season units
with total NOX emissions exceeding the
State assurance level for a control
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period in a given year, as described in
§ 97.506(c)(2)(iii):
(i) By July 1 immediately after the
promulgation of such notice, the
designated representative of each TR
NOX Ozone Season source in each such
State (and Indian country within the
borders of such State) shall submit a
statement, in a format prescribed by the
Administrator, providing for each TR
NOX Ozone Season unit (if any) at the
source that operates during, but is not
allocated an amount of TR NOX Ozone
Season allowances for, such control
period, the unit’s allowable NOX
emission rate for such control period
and, if such rate is expressed in lb per
mmBtu, the unit’s heat rate.
(ii) By August 1 immediately after the
promulgation of such notice, the
Administrator will calculate, for each
such State (and Indian country within
the borders of such State) and such
control period and each common
designated representative for such
control period for a group of one or
more TR NOX Ozone Season sources
and units in the State (and Indian
country within the borders of such
State), the common designated
representative’s share of the total NOX
emissions from all TR NOX Ozone
Season units at TR NOX Ozone Season
sources in the State (and Indian country
within the borders of such State), the
common designated representative’s
assurance level, and the amount (if any)
of TR NOX Ozone Season allowances
that the owners and operators of such
group of sources and units must hold in
accordance with the calculation formula
in § 97.506(c)(2)(i) and will promulgate
a notice of data availability of the results
of these calculations.
(iii) The Administrator will provide
an opportunity for submission of
objections to the calculations referenced
by the notice of data availability
required in paragraph (b)(2)(ii) of this
section and the calculations referenced
by the relevant notice of data
availability required in paragraph
(b)(1)(i) of this section.
(A) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations referenced in
the relevant notice required under
paragraph (b)(1)(ii) of this section and
referenced in the notice required under
paragraph (b)(2)(ii) of this section are in
accordance with § 97.506(c)(2)(iii),
§§ 97.506(b) and 97.530 through 97.535,
the definitions of ‘‘common designated
representative’’, ‘‘common designated
representative’s assurance level’’, and
‘‘common designated representative’s
share’’ in § 97.502, and the calculation
formula in § 97.506(c)(2)(i).
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19:20 Aug 05, 2011
Jkt 223001
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(2)(iii)(A) of this section. By October
1 immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of data availability
of any adjustments that the
Administrator determines to be
necessary and the reasons for accepting
or rejecting any objections submitted in
accordance with paragraph (b)(2)(iii)(A)
of this section.
(3) For any State (and Indian country
within the borders of such State)
referenced in each notice of data
availability required in paragraph
(b)(2)(iii)(B) of this section as having TR
NOX Ozone Season units with total NOX
emissions exceeding the State assurance
level for a control period in a given year,
the Administrator will establish one
assurance account for each set of owners
and operators referenced, in the notice
of data availability required under
paragraph (b)(2)(iii)(B) of this section, as
all of the owners and operators of a
group of TR NOX Ozone Season sources
and units in the State (and Indian
country within the borders of such
State) having a common designated
representative for such control period
and as being required to hold TR NOX
Ozone Season allowances.
(4)(i) As of midnight of November 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(iii)(B) of this section,
the owners and operators described in
paragraph (b)(3) of this section shall
hold in the assurance account
established for the them and for the
appropriate TR NOX Ozone Season
sources, TR NOX Ozone Season units,
and State (and Indian country within
the borders of such State) under
paragraph (b)(3) of this section a total
amount of TR NOX Ozone Season
allowances, available for deduction
under paragraph (a) of this section,
equal to the amount such owners and
operators are required to hold with
regard to such sources, units and State
(and Indian country within the borders
of such State) as calculated by the
Administrator and referenced in such
notice.
(ii) Notwithstanding the allowanceholding deadline specified in paragraph
(b)(4)(i) of this section, if November 1 is
not a business day, then such
allowance-holding deadline shall be
midnight of the first business day
thereafter.
(5) After November 1 (or the date
described in paragraph (b)(4)(ii) of this
section) immediately after the
promulgation of each notice of data
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48427
availability required in paragraph
(b)(2)(iii)(B) of this section and after the
recordation, in accordance with
§ 97.523, of TR NOX Ozone Season
allowance transfers submitted by
midnight of such date, the
Administrator will determine whether
the owners and operators described in
paragraph (b)(3) of this section hold, in
the assurance account for the
appropriate TR NOX Ozone Season
sources, TR NOX Ozone Season units,
and State (and Indian country within
the borders of such State) established
under paragraph (b)(3) of this section,
the amount of TR NOX Ozone Season
allowances available under paragraph
(a) of this section that the owners and
operators are required to hold with
regard to such sources, units, and State
(and Indian country within the borders
of such State) as calculated by the
Administrator and referenced in the
notice required in paragraph
(b)(2)(iii)(B) of this section.
(6) Notwithstanding any other
provision of this subpart and any
revision, made by or submitted to the
Administrator after the promulgation of
the notice of data availability required
in paragraph (b)(2)(iii)(B) of this section
for a control period in a given year, of
any data used in making the
calculations referenced in such notice,
the amounts of TR NOX Ozone Season
allowances that the owners and
operators are required to hold in
accordance with § 97.506(c)(2)(i) for
such control period shall continue to be
such amounts as calculated by the
Administrator and referenced in such
notice required in paragraph
(b)(2)(iii)(B) of this section, except as
follows:
(i) If any such data are revised by the
Administrator as a result of a decision
in or settlement of litigation concerning
such data on appeal under part 78 of
this chapter of such notice, or on appeal
under section 307 of the Clean Air Act
of a decision rendered under part 78 of
this chapter on appeal of such notice,
then the Administrator will use the data
as so revised to recalculate the amounts
of TR NOX Ozone Season allowances
that owners and operators are required
to hold in accordance with the
calculation formula in § 97.506(c)(2)(i)
for such control period with regard to
the TR NOX Ozone Season sources, TR
NOX Ozone Season units, and State (and
Indian country within the borders of
such State) involved, provided that such
litigation under part 78 of this chapter,
or the proceeding under part 78 of this
chapter that resulted in the decision
appealed in such litigation under
section 307 of the Clean Air Act, was
initiated no later than 30 days after
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promulgation of such notice required in
paragraph (b)(2)(iii)(B) of this section.
(ii) If any such data are revised by the
owners and operators of a TR NOX
Ozone Season source and TR NOX
Ozone Season unit whose designated
representative submitted such data
under paragraph (b)(2)(i) of this section,
as a result of a decision in or settlement
of litigation concerning such
submission, then the Administrator will
use the data as so revised to recalculate
the amounts of TR NOX Ozone Season
allowances that owners and operators
are required to hold in accordance with
the calculation formula in
§ 97.506(c)(2)(i) for such control period
with regard to the TR NOX Ozone
Season sources, TR NOX Ozone Season
units, and State (and Indian country
within the borders of such State)
involved, provided that such litigation
was initiated no later than 30 days after
promulgation of such notice required in
paragraph (b)(2)(iii)(B) of this section.
(iii) If the revised data are used to
recalculate, in accordance with
paragraphs (b)(6)(i) and (ii) of this
section, the amount of TR NOX Ozone
Season allowances that the owners and
operators are required to hold for such
control period with regard to the TR
NOX Ozone Season sources, TR NOX
Ozone Season units, and State (and
Indian country within the borders of
such State) involved—
(A) Where the amount of TR NOX
Ozone Season allowances that the
owners and operators are required to
hold increases as a result of the use of
all such revised data, the Administrator
will establish a new, reasonable
deadline on which the owners and
operators shall hold the additional
amount of TR NOX Ozone Season
allowances in the assurance account
established by the Administrator for the
appropriate TR NOX Ozone Season
sources, TR NOX Ozone Season units,
and State (and Indian country within
the borders of such State) under
paragraph (b)(3) of this section. The
owners’ and operators’ failure to hold
such additional amount, as required,
before the new deadline shall not be a
violation of the Clean Air Act. The
owners’ and operators’ failure to hold
such additional amount, as required, as
of the new deadline shall be a violation
of the Clean Air Act. Each TR NOX
Ozone Season allowance that the
owners and operators fail to hold as
required as of the new deadline, and
each day in such control period, shall be
a separate violation of the Clean Air Act.
(B) For the owners and operators for
which the amount of TR NOX Ozone
Season allowances required to be held
decreases as a result of the use of all
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such revised data, the Administrator
will record, in all accounts from which
TR NOX Ozone Season allowances were
transferred by such owners and
operators for such control period to the
assurance account established by the
Administrator for the appropriate at TR
NOX Ozone Season sources, TR NOX
Ozone Season units, and State (and
Indian country within the borders of
such State) under paragraph (b)(3) of
this section, a total amount of the TR
NOX Ozone Season allowances held in
such assurance account equal to the
amount of the decrease. If TR NOX
Ozone Season allowances were
transferred to such assurance account
from more than one account, the
amount of TR NOX Ozone Season
allowances recorded in each such
transferor account will be in proportion
to the percentage of the total amount of
TR NOX Ozone Season allowances
transferred to such assurance account
for such control period from such
transferor account.
(C) Each TR NOX Ozone Season
allowance held under paragraph
(b)(6)(iii)(A) of this section as a result of
recalculation of requirements under the
TR NOX Ozone Season assurance
provisions for such control period must
be a TR NOX Ozone Season allowance
allocated for a control period in a year
before or the year immediately
following, or in the same year as, the
year of such control period.
§ 97.526
Banking.
(a) A TR NOX Ozone Season
allowance may be banked for future use
or transfer in a compliance account or
a general account in accordance with
paragraph (b) of this section.
(b) Any TR NOX Ozone Season
allowance that is held in a compliance
account or a general account will
remain in such account unless and until
the TR NOX Ozone Season allowance is
deducted or transferred under
§ 97.511(c), § 97.523, § 97.524, § 97.525,
§ 97.527, or § 97.528.
§ 97.527
Account error.
The Administrator may, at his or her
sole discretion and on his or her own
motion, correct any error in any
Allowance Management System
account. Within 10 business days of
making such correction, the
Administrator will notify the authorized
account representative for the account.
§ 97.528 Administrator’s action on
submissions.
(a) The Administrator may review and
conduct independent audits concerning
any submission under the TR NOX
Ozone Season Trading Program and
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make appropriate adjustments of the
information in the submission.
(b) The Administrator may deduct TR
NOX Ozone Season allowances from or
transfer TR NOX Ozone Season
allowances to a compliance account or
an assurance account, based on the
information in a submission, as adjusted
under paragraph (a)(1) of this section,
and record such deductions and
transfers.
§ 97.529
[Reserved]
§ 97.530 General monitoring,
recordkeeping, and reporting requirements.
The owners and operators, and to the
extent applicable, the designated
representative, of a TR NOX Ozone
Season unit, shall comply with the
monitoring, recordkeeping, and
reporting requirements as provided in
this subpart and subpart H of part 75 of
this chapter. For purposes of applying
such requirements, the definitions in
§ 97.502 and in § 72.2 of this chapter
shall apply, the terms ‘‘affected unit,’’
‘‘designated representative,’’ and
‘‘continuous emission monitoring
system’’ (or ‘‘CEMS’’) in part 75 of this
chapter shall be deemed to refer to the
terms ‘‘TR NOX Ozone Season unit,’’
‘‘designated representative,’’ and
‘‘continuous emission monitoring
system’’ (or ‘‘CEMS’’) respectively as
defined in § 97.502, and the term
‘‘newly affected unit’’ shall be deemed
to mean ‘‘newly affected TR NOX Ozone
Season unit’’. The owner or operator of
a unit that is not a TR NOX Ozone
Season unit but that is monitored under
§ 75.72(b)(2)(ii) of this chapter shall
comply with the same monitoring,
recordkeeping, and reporting
requirements as a TR NOX Ozone
Season unit.
(a) Requirements for installation,
certification, and data accounting. The
owner or operator of each TR NOX
Ozone Season unit shall:
(1) Install all monitoring systems
required under this subpart for
monitoring NOX mass emissions and
individual unit heat input (including all
systems required to monitor NOX
emission rate, NOX concentration, stack
gas moisture content, stack gas flow
rate, CO2 or O2 concentration, and fuel
flow rate, as applicable, in accordance
with §§ 75.71 and 75.72 of this chapter);
(2) Successfully complete all
certification tests required under
§ 97.531 and meet all other
requirements of this subpart and part 75
of this chapter applicable to the
monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure
the data from the monitoring systems
under paragraph (a)(1) of this section.
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(b) Compliance deadlines. Except as
provided in paragraph (e) of this
section, the owner or operator shall
meet the monitoring system certification
and other requirements of paragraphs
(a)(1) and (2) of this section on or before
the following dates and shall record,
report, and quality-assure the data from
the monitoring systems under paragraph
(a)(1) of this section on and after the
following dates.
(1) For the owner or operator of a TR
NOX Ozone Season unit that
commences commercial operation
before July 1, 2011, May 1, 2012.
(2) For the owner or operator of a TR
NOX Ozone Season unit that
commences commercial operation on or
after July 1, 2011 and that reports on an
annual basis under § 97.534(d), by the
later of the following:
(i) 180 calendar days after the date on
which the unit commences commercial
operation; or
(ii) May 1, 2012.
(3) For the owner or operator of a TR
NOX Ozone Season unit that
commences commercial operation on or
after July 1, 2011 and that reports on a
control period basis under
§ 97.534(d)(2)(ii), by the following date:
(i) 180 calendar days after the date on
which the unit commences commercial
operation; or
(ii) If the compliance date under
paragraph (b)(3)(i) of this section is not
during a control period, May 1
immediately after the compliance date
under paragraph (b)(3)(i) of this section.
(4) The owner or operator of a TR
NOX Ozone Season unit for which
construction of a new stack or flue or
installation of add-on NOX emission
controls is completed after the
applicable deadline under paragraph
(b)(1), (2), or (3) of this section shall
meet the requirements of §§ 75.4(e)(1)
through (e)(4) of this chapter, except
that:
(i) Such requirements shall apply to
the monitoring systems required under
§ 97.530 through § 97.535, rather than
the monitoring systems required under
part 75 of this chapter;
(ii) NOX emission rate, NOX
concentration, stack gas moisture
content, stack gas volumetric flow rate,
and O2 or CO2 concentration data shall
be determined and reported, rather than
the data listed in § 75.4(e)(2) of this
chapter; and
(iii) Any petition for another
procedure under § 75.4(e)(2) of this
chapter shall be submitted under
§ 97.535, rather than § 75.66.
(c) Reporting data. The owner or
operator of a TR NOX Ozone Season unit
that does not meet the applicable
compliance date set forth in paragraph
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(b) of this section for any monitoring
system under paragraph (a)(1) of this
section shall, for each such monitoring
system, determine, record, and report
maximum potential (or, as appropriate,
minimum potential) values for NOX
concentration, NOX emission rate, stack
gas flow rate, stack gas moisture
content, fuel flow rate, and any other
parameters required to determine NOX
mass emissions and heat input in
accordance with § 75.31(b)(2) or (c)(3) of
this chapter, section 2.4 of appendix D
to part 75 of this chapter, or section 2.5
of appendix E to part 75 of this chapter,
as applicable.
(d) Prohibitions. (1) No owner or
operator of a TR NOX Ozone Season unit
shall use any alternative monitoring
system, alternative reference method, or
any other alternative to any requirement
of this subpart without having obtained
prior written approval in accordance
with § 97.535.
(2) No owner or operator of a TR NOX
Ozone Season unit shall operate the unit
so as to discharge, or allow to be
discharged, NOX to the atmosphere
without accounting for all such NOX in
accordance with the applicable
provisions of this subpart and part 75 of
this chapter.
(3) No owner or operator of a TR NOX
Ozone Season unit shall disrupt the
continuous emission monitoring system,
any portion thereof, or any other
approved emission monitoring method,
and thereby avoid monitoring and
recording NOX mass discharged into the
atmosphere or heat input, except for
periods of recertification or periods
when calibration, quality assurance
testing, or maintenance is performed in
accordance with the applicable
provisions of this subpart and part 75 of
this chapter.
(4) No owner or operator of a TR NOX
Ozone Season unit shall retire or
permanently discontinue use of the
continuous emission monitoring system,
any component thereof, or any other
approved monitoring system under this
subpart, except under any one of the
following circumstances:
(i) During the period that the unit is
covered by an exemption under § 97.505
that is in effect;
(ii) The owner or operator is
monitoring emissions from the unit with
another certified monitoring system
approved, in accordance with the
applicable provisions of this subpart
and part 75 of this chapter, by the
Administrator for use at that unit that
provides emission data for the same
pollutant or parameter as the retired or
discontinued monitoring system; or
(iii) The designated representative
submits notification of the date of
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48429
certification testing of a replacement
monitoring system for the retired or
discontinued monitoring system in
accordance with § 97.531(d)(3)(i).
(e) Long-term cold storage. The owner
or operator of a TR NOX Ozone Season
unit is subject to the applicable
provisions of § 75.4(d) of this chapter
concerning units in long-term cold
storage.
§ 97.531 Initial monitoring system
certification and recertification procedures.
(a) The owner or operator of a TR NOX
Ozone Season unit shall be exempt from
the initial certification requirements of
this section for a monitoring system
under § 97.530(a)(1) if the following
conditions are met:
(1) The monitoring system has been
previously certified in accordance with
part 75 of this chapter; and
(2) The applicable quality-assurance
and quality-control requirements of
§ 75.21 of this chapter and appendices
B, D, and E to part 75 of this chapter are
fully met for the certified monitoring
system described in paragraph (a)(1) of
this section.
(b) The recertification provisions of
this section shall apply to a monitoring
system under § 97.530(a)(1) that is
exempt from initial certification
requirements under paragraph (a) of this
section.
(c) If the Administrator has previously
approved a petition under § 75.17(a) or
(b) of this chapter for apportioning the
NOX emission rate measured in a
common stack or a petition under
§ 75.66 of this chapter for an alternative
to a requirement in § 75.12 or § 75.17 of
this chapter, the designated
representative shall resubmit the
petition to the Administrator under
§ 97.535 to determine whether the
approval applies under the TR NOX
Ozone Season Trading Program.
(d) Except as provided in paragraph
(a) of this section, the owner or operator
of a TR NOX Ozone Season unit shall
comply with the following initial
certification and recertification
procedures for a continuous monitoring
system (i.e., a continuous emission
monitoring system and an excepted
monitoring system under appendices D
and E to part 75 of this chapter) under
§ 97.530(a)(1). The owner or operator of
a unit that qualifies to use the low mass
emissions excepted monitoring
methodology under § 75.19 of this
chapter or that qualifies to use an
alternative monitoring system under
subpart E of part 75 of this chapter shall
comply with the procedures in
paragraph (e) or (f) of this section
respectively.
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(1) Requirements for initial
certification. The owner or operator
shall ensure that each continuous
monitoring system under § 97.530(a)(1)
(including the automated data
acquisition and handling system)
successfully completes all of the initial
certification testing required under
§ 75.20 of this chapter by the applicable
deadline in § 97.530(b). In addition,
whenever the owner or operator installs
a monitoring system to meet the
requirements of this subpart in a
location where no such monitoring
system was previously installed, initial
certification in accordance with § 75.20
of this chapter is required.
(2) Requirements for recertification.
Whenever the owner or operator makes
a replacement, modification, or change
in any certified continuous emission
monitoring system under § 97.530(a)(1)
that may significantly affect the ability
of the system to accurately measure or
record NOX mass emissions or heat
input rate or to meet the qualityassurance and quality-control
requirements of § 75.21 of this chapter
or appendix B to part 75 of this chapter,
the owner or operator shall recertify the
monitoring system in accordance with
§ 75.20(b) of this chapter. Furthermore,
whenever the owner or operator makes
a replacement, modification, or change
to the flue gas handling system or the
unit’s operation that may significantly
change the stack flow or concentration
profile, the owner or operator shall
recertify each continuous emission
monitoring system whose accuracy is
potentially affected by the change, in
accordance with § 75.20(b) of this
chapter. Examples of changes to a
continuous emission monitoring system
that require recertification include:
replacement of the analyzer, complete
replacement of an existing continuous
emission monitoring system, or change
in location or orientation of the
sampling probe or site. Any fuel
flowmeter system, and any excepted
NOX monitoring system under appendix
E to part 75 of this chapter, under
§ 97.530(a)(1) are subject to the
recertification requirements in
§ 75.20(g)(6) of this chapter.
(3) Approval process for initial
certification and recertification. For
initial certification of a continuous
monitoring system under § 97.530(a)(1),
paragraphs (d)(3)(i) through (v) of this
section apply. For recertifications of
such monitoring systems, paragraphs
(d)(3)(i) through (iv) of this section and
the procedures in §§ 75.20(b)(5) and
(g)(7) of this chapter (in lieu of the
procedures in paragraph (d)(3)(v) of this
section) apply, provided that in
applying paragraphs (d)(3)(i) through
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(iv) of this section, the words
‘‘certification’’ and ‘‘initial certification’’
are replaced by the word
‘‘recertification’’ and the word
‘‘certified’’ is replaced by with the word
‘‘recertified’’.
(i) Notification of certification. The
designated representative shall submit
to the appropriate EPA Regional Office
and the Administrator written notice of
the dates of certification testing, in
accordance with § 97.533.
(ii) Certification application. The
designated representative shall submit
to the Administrator a certification
application for each monitoring system.
A complete certification application
shall include the information specified
in § 75.63 of this chapter.
(iii) Provisional certification date. The
provisional certification date for a
monitoring system shall be determined
in accordance with § 75.20(a)(3) of this
chapter. A provisionally certified
monitoring system may be used under
the TR NOX Ozone Season Trading
Program for a period not to exceed 120
days after receipt by the Administrator
of the complete certification application
for the monitoring system under
paragraph (d)(3)(ii) of this section. Data
measured and recorded by the
provisionally certified monitoring
system, in accordance with the
requirements of part 75 of this chapter,
will be considered valid quality-assured
data (retroactive to the date and time of
provisional certification), provided that
the Administrator does not invalidate
the provisional certification by issuing a
notice of disapproval within 120 days of
the date of receipt of the complete
certification application by the
Administrator.
(iv) Certification application approval
process. The Administrator will issue a
written notice of approval or
disapproval of the certification
application to the owner or operator
within 120 days of receipt of the
complete certification application under
paragraph (d)(3)(ii) of this section. In the
event the Administrator does not issue
such a notice within such 120-day
period, each monitoring system that
meets the applicable performance
requirements of part 75 of this chapter
and is included in the certification
application will be deemed certified for
use under the TR NOX Ozone Season
Trading Program.
(A) Approval notice. If the
certification application is complete and
shows that each monitoring system
meets the applicable performance
requirements of part 75 of this chapter,
then the Administrator will issue a
written notice of approval of the
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certification application within 120
days of receipt.
(B) Incomplete application notice. If
the certification application is not
complete, then the Administrator will
issue a written notice of incompleteness
that sets a reasonable date by which the
designated representative must submit
the additional information required to
complete the certification application. If
the designated representative does not
comply with the notice of
incompleteness by the specified date,
then the Administrator may issue a
notice of disapproval under paragraph
(d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the
certification application shows that any
monitoring system does not meet the
performance requirements of part 75 of
this chapter or if the certification
application is incomplete and the
requirement for disapproval under
paragraph (d)(3)(iv)(B) of this section is
met, then the Administrator will issue a
written notice of disapproval of the
certification application. Upon issuance
of such notice of disapproval, the
provisional certification is invalidated
by the Administrator and the data
measured and recorded by each
uncertified monitoring system shall not
be considered valid quality-assured data
beginning with the date and hour of
provisional certification (as defined
under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The
Administrator may issue a notice of
disapproval of the certification status of
a monitor in accordance with
§ 97.532(b).
(v) Procedures for loss of certification.
If the Administrator issues a notice of
disapproval of a certification
application under paragraph
(d)(3)(iv)(C) of this section or a notice of
disapproval of certification status under
paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall
substitute the following values, for each
disapproved monitoring system, for
each hour of unit operation during the
period of invalid data specified under
§ 75.20(a)(4)(iii), § 75.20(g)(7), or
§ 75.21(e) of this chapter and continuing
until the applicable date and hour
specified under § 75.20(a)(5)(i) or (g)(7)
of this chapter:
(1) For a disapproved NOX emission
rate (i.e., NOX-diluent) system, the
maximum potential NOX emission rate,
as defined in § 72.2 of this chapter.
(2) For a disapproved NOX pollutant
concentration monitor and disapproved
flow monitor, respectively, the
maximum potential concentration of
NOX and the maximum potential flow
rate, as defined in sections 2.1.2.1 and
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2.1.4.1 of appendix A to part 75 of this
chapter.
(3) For a disapproved moisture
monitoring system and disapproved
diluent gas monitoring system,
respectively, the minimum potential
moisture percentage and either the
maximum potential CO2 concentration
or the minimum potential O2
concentration (as applicable), as defined
in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(4) For a disapproved fuel flowmeter
system, the maximum potential fuel
flow rate, as defined in section 2.4.2.1
of appendix D to part 75 of this chapter.
(5) For a disapproved excepted NOX
monitoring system under appendix E to
part 75 of this chapter, the fuel-specific
maximum potential NOX emission rate,
as defined in § 72.2 of this chapter.
(B) The designated representative
shall submit a notification of
certification retest dates and a new
certification application in accordance
with paragraphs (d)(3)(i) and (ii) of this
section.
(C) The owner or operator shall repeat
all certification tests or other
requirements that were failed by the
monitoring system, as indicated in the
Administrator’s notice of disapproval,
no later than 30 unit operating days
after the date of issuance of the notice
of disapproval.
(e) The owner or operator of a unit
qualified to use the low mass emissions
(LME) excepted methodology under
§ 75.19 of this chapter shall meet the
applicable certification and
recertification requirements in
§§ 75.19(a)(2) and 75.20(h) of this
chapter. If the owner or operator of such
a unit elects to certify a fuel flowmeter
system for heat input determination, the
owner or operator shall also meet the
certification and recertification
requirements in § 75.20(g) of this
chapter.
(f) The designated representative of
each unit for which the owner or
operator intends to use an alternative
monitoring system approved by the
Administrator under subpart E of part
75 of this chapter shall comply with the
applicable notification and application
procedures of § 75.20(f) of this chapter.
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§ 97.532 Monitoring system out-of-control
periods.
(a) General provisions. Whenever any
monitoring system fails to meet the
quality-assurance and quality-control
requirements or data validation
requirements of part 75 of this chapter,
data shall be substituted using the
applicable missing data procedures in
subpart D or subpart H of, or appendix
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D or appendix E to, part 75 of this
chapter.
(b) Audit decertification. Whenever
both an audit of a monitoring system
and a review of the initial certification
or recertification application reveal that
any monitoring system should not have
been certified or recertified because it
did not meet a particular performance
specification or other requirement under
§ 97.531 or the applicable provisions of
part 75 of this chapter, both at the time
of the initial certification or
recertification application submission
and at the time of the audit, the
Administrator will issue a notice of
disapproval of the certification status of
such monitoring system. For the
purposes of this paragraph, an audit
shall be either a field audit or an audit
of any information submitted to the
Administrator or any State or permitting
authority. By issuing the notice of
disapproval, the Administrator revokes
prospectively the certification status of
the monitoring system. The data
measured and recorded by the
monitoring system shall not be
considered valid quality-assured data
from the date of issuance of the
notification of the revoked certification
status until the date and time that the
owner or operator completes
subsequently approved initial
certification or recertification tests for
the monitoring system. The owner or
operator shall follow the applicable
initial certification or recertification
procedures in § 97.531 for each
disapproved monitoring system.
§ 97.533 Notifications concerning
monitoring.
The designated representative of a TR
NOX Ozone Season unit shall submit
written notice to the Administrator in
accordance with § 75.61 of this chapter.
§ 97.534
Recordkeeping and reporting.
(a) General provisions. The designated
representative shall comply with all
recordkeeping and reporting
requirements in paragraphs (b) through
(e) of this section, the applicable
recordkeeping and reporting
requirements under § 75.73 of this
chapter, and the requirements of
§ 97.514(a).
(b) Monitoring plans. The owner or
operator of a TR NOX Ozone Season unit
shall comply with requirements of
§ 75.73(c) and (e) of this chapter.
(c) Certification applications. The
designated representative shall submit
an application to the Administrator
within 45 days after completing all
initial certification or recertification
tests required under § 97.531, including
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48431
the information required under § 75.63
of this chapter.
(d) Quarterly reports. The designated
representative shall submit quarterly
reports, as follows:
(1) If the TR NOX Ozone Season unit
is subject to the Acid Rain Program or
a TR NOX Annual emissions limitation
or if the owner or operator of such unit
chooses to report on an annual basis
under this subpart, the designated
representative shall meet the
requirements of subpart H of part 75 of
this chapter (concerning monitoring of
NOX mass emissions) for such unit for
the entire year and shall report the NOX
mass emissions data and heat input data
for such unit, in an electronic quarterly
report in a format prescribed by the
Administrator, for each calendar quarter
beginning with:
(i) For a unit that commences
commercial operation before July 1,
2011, the calendar quarter covering May
1, 2012 through June 30, 2012; or
(ii) For a unit that commences
commercial operation on or after July 1,
2011, the calendar quarter
corresponding to the earlier of the date
of provisional certification or the
applicable deadline for initial
certification under § 97.530(b), unless
that quarter is the third or fourth quarter
of 2011 or the first quarter of 2012, in
which case reporting shall commence in
the quarter covering May 1, 2012
through June 30, 2012.
(2) If the TR NOX Ozone Season unit
is not subject to the Acid Rain Program
or a TR NOX Annual emissions
limitation, then the designated
representative shall either:
(i) Meet the requirements of subpart H
of part 75 (concerning monitoring of
NOX mass emissions) for such unit for
the entire year and report the NOX mass
emissions data and heat input data for
such unit in accordance with paragraph
(d)(1) of this section; or
(ii) Meet the requirements of subpart
H of part 75 for the control period
(including the requirements in
§ 75.74(c) of this chapter) and report
NOX mass emissions data and heat
input data (including the data described
in § 75.74(c)(6) of this chapter) for such
unit only for the control period of each
year and report, in an electronic
quarterly report in a format prescribed
by the Administrator, for each calendar
quarter beginning with:
(A) For a unit that commences
commercial operation before July 1,
2011, the calendar quarter covering May
1, 2012 through June 30, 2012; or
(B) For a unit that commences
commercial operation on or after July 1,
2011, the calendar quarter
corresponding to the earlier of the date
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of provisional certification or the
applicable deadline for initial
certification under § 97.530(b), unless
that date is not during a control period,
in which case reporting shall commence
in the quarter that includes May 1
through June 30 of the first control
period after such date.
(3) The designated representative
shall submit each quarterly report to the
Administrator within 30 days after the
end of the calendar quarter covered by
the report. Quarterly reports shall be
submitted in the manner specified in
§ 75.73(f) of this chapter.
(4) For TR NOX Ozone Season units
that are also subject to the Acid Rain
Program, TR NOX Annual Trading
Program, TR SO2 Group 1 Trading
Program, or TR SO2 Group 2 Trading
Program, quarterly reports shall include
the applicable data and information
required by subparts F through H of part
75 of this chapter as applicable, in
addition to the NOX mass emission data,
heat input data, and other information
required by this subpart.
(5) The Administrator may review and
conduct independent audits of any
quarterly report in order to determine
whether the quarterly report meets the
requirements of this subpart and part 75
of this chapter, including the
requirement to use substitute data.
(i) The Administrator will notify the
designated representative of any
determination that the quarterly report
fails to meet any such requirements and
specify in such notification any
corrections that the Administrator
believes are necessary to make through
resubmission of the quarterly report and
a reasonable time period within which
the designated representative must
respond. Upon request by the
designated representative, the
Administrator may specify reasonable
extensions of such time period. Within
the time period (including any such
extensions) specified by the
Administrator, the designated
representative shall resubmit the
quarterly report with the corrections
specified by the Administrator, except
to the extent the designated
representative provides information
demonstrating that a specified
correction is not necessary because the
quarterly report already meets the
requirements of this subpart and part 75
of this chapter that are relevant to the
specified correction.
(6) Any resubmission of a quarterly
report shall meet the requirements
applicable to the submission of a
quarterly report under this subpart and
part 75 of this chapter, except for the
deadline set forth in paragraph (d)(3) of
this section.
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(e) Compliance certification. The
designated representative shall submit
to the Administrator a compliance
certification (in a format prescribed by
the Administrator) in support of each
quarterly report based on reasonable
inquiry of those persons with primary
responsibility for ensuring that all of the
unit’s emissions are correctly and fully
monitored. The certification shall state
that:
(1) The monitoring data submitted
were recorded in accordance with the
applicable requirements of this subpart
and part 75 of this chapter, including
the quality assurance procedures and
specifications;
(2) For a unit with add-on NOX
emission controls and for all hours
where NOX data are substituted in
accordance with § 75.34(a)(1) of this
chapter, the add-on emission controls
were operating within the range of
parameters listed in the quality
assurance/quality control program
under appendix B to part 75 of this
chapter and the substitute data values
do not systematically underestimate
NOX emissions; and
(3) For a unit that is reporting on a
control period basis under paragraph
(d)(2)(ii) of this section, the NOX
emission rate and NOX concentration
values substituted for missing data
under subpart D of part 75 of this
chapter are calculated using only values
from a control period and do not
systematically underestimate NOX
emissions.
§ 97.535 Petitions for alternatives to
monitoring, recordkeeping, or reporting
requirements.
(a) The designated representative of a
TR NOX Ozone Season unit may submit
a petition under § 75.66 of this chapter
to the Administrator, requesting
approval to apply an alternative to any
requirement of §§ 97.530 through
97.534.
(b) A petition submitted under
paragraph (a) of this section shall
include sufficient information for the
evaluation of the petition, including, at
a minimum, the following information:
(i) Identification of each unit and
source covered by the petition;
(ii) A detailed explanation of why the
proposed alternative is being suggested
in lieu of the requirement;
(iii) A description and diagram of any
equipment and procedures used in the
proposed alternative;
(iv) A demonstration that the
proposed alternative is consistent with
the purposes of the requirement for
which the alternative is proposed and
with the purposes of this subpart and
part 75 of this chapter and that any
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adverse effect of approving the
alternative will be de minimis: and
(v) Any other relevant information
that the Administrator may require.
(c) Use of an alternative to any
requirement referenced in paragraph (a)
of this section is in accordance with this
subpart only to the extent that the
petition is approved in writing by the
Administrator and that such use is in
accordance with such approval.
76. Part 97 is amended by adding
subpart CCCCC to read as follows:
Subpart CCCCC—TR SO2 Group 1
Trading Program
Sec.
97.601 Purpose.
97.602 Definitions.
97.603 Measurements, abbreviations, and
acronyms.
97.604 Applicability.
97.605 Retired unit exemption.
97.606 Standard requirements.
97.607 Computation of time.
97.608 Administrative appeal procedures.
97.609 [Reserved]
97.610 State SO2 Group 1 trading budgets,
new unit set-asides, Indian country new
unit set-asides and variability limits.
97.611 Timing requirements for TR SO2
Group 1 allowance allocations.
97.612 TR SO2 Group 1 allowance
allocations to new units.
97.613 Authorization of designated
representative and alternate designated
representative.
97.614 Responsibilities of designated
representative and alternate designated
representative.
97.615 Changing designated representative
and alternate designated representative;
changes in owners and operators.
97.616 Certificate of representation.
97.617 Objections concerning designated
representative and alternate designated
representative.
97.618 Delegation by designated
representative and alternate designated
representative.
97.619 [Reserved]
97.620 Establishment of compliance
accounts and general accounts.
97.621 Recordation of TR SO2 Group 1
allowance allocations.
97.622 Submission of TR SO2 Group 1
allowance transfers.
97.623 Recordation of TR SO2 Group 1
allowance transfers.
97.624 Compliance with TR SO2 Group 1
emissions limitation.
97.625 Compliance with TR SO2 Group 1
assurance provisions.
97.626 Banking.
97.627 Account error.
97.628 Administrator’s action on
submissions.
97.629 [Reserved]
97.630 General monitoring, recordkeeping,
and reporting requirements.
97.631 Initial monitoring system
certification and recertification
procedures.
97.632 Monitoring system out-of-control
periods.
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97.633 Notifications concerning
monitoring.
97.634 Recordkeeping and reporting.
97.635 Petitions for alternatives to
monitoring, recordkeeping, or reporting
requirements.
Subpart CCCCC—TR SO2 Group 1
Trading Program
§ 97.601
Purpose.
This subpart sets forth the general,
designated representative, allowance,
and monitoring provisions for the
Transport Rule (TR) SO2 Group 1
Trading Program, under section 110 of
the Clean Air Act and § 52.39 of this
chapter, as a means of mitigating
interstate transport of fine particulates
and sulfur dioxide.
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§ 97.602
Definitions.
The terms used in this subpart shall
have the meanings set forth in this
section as follows:
Acid Rain Program means a multistate SO2 and NOX air pollution control
and emission reduction program
established by the Administrator under
title IV of the Clean Air Act and parts
72 through 78 of this chapter.
Administrator means the
Administrator of the United States
Environmental Protection Agency or the
Director of the Clean Air Markets
Division (or its successor determined by
the Administrator) of the United States
Environmental Protection Agency, the
Administrator’s duly authorized
representative under this subpart.
Allocate or allocation means, with
regard to TR SO2 Group 1 allowances,
the determination by the Administrator,
State, or permitting authority, in
accordance with this subpart and any
SIP revision submitted by the State and
approved by the Administrator under
§ 52.39(d), (e), or (f) of this chapter, of
the amount of such TR SO2 Group 1
allowances to be initially credited, at no
cost to the recipient, to:
(1) A TR SO2 Group 1 unit;
(2) A new unit set-aside;
(3) An Indian country new unit setaside; or
(4) An entity not listed in paragraphs
(1) through (3) of this definition;
(5) Provided that, if the
Administrator, State, or permitting
authority initially credits, to a TR SO2
Group 1 unit qualifying for an initial
credit, a credit in the amount of zero TR
SO2 Group 1 allowances, the TR SO2
Group 1 unit will be treated as being
allocated an amount (i.e., zero) of TR
SO2 Group 1 allowances.
Allowable SO2 emission rate means,
for a unit, the most stringent State or
federal SO2 emission rate limit (in lb/
MWhr or, if in lb/mmBtu, converted to
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lb/MWhr by multiplying it by the unit’s
heat rate in mmBtu/MWhr) that is
applicable to the unit and covers the
longest averaging period not exceeding
one year.
Allowance Management System
means the system by which the
Administrator records allocations,
deductions, and transfers of TR SO2
Group 1 allowances under the TR SO2
Group 1 Trading Program. Such
allowances are allocated, recorded,
held, deducted, or transferred only as
whole allowances.
Allowance Management System
account means an account in the
Allowance Management System
established by the Administrator for
purposes of recording the allocation,
holding, transfer, or deduction of TR
SO2 Group 1 allowances.
Allowance transfer deadline means,
for a control period in a given year,
midnight of March 1 (if it is a business
day), or midnight of the first business
day thereafter (if March 1 is not a
business day), immediately after such
control period and is the deadline by
which a TR SO2 Group 1 allowance
transfer must be submitted for
recordation in a TR SO2 Group 1
source’s compliance account in order to
be available for use in complying with
the source’s TR SO2 Group 1 emissions
limitation for such control period in
accordance with §§ 97.606 and 97.624.
Alternate designated representative
means, for a TR SO2 Group 1 source and
each TR SO2 Group 1 unit at the source,
the natural person who is authorized by
the owners and operators of the source
and all such units at the source, in
accordance with this subpart, to act on
behalf of the designated representative
in matters pertaining to the TR SO2
Group 1 Trading Program. If the TR SO2
Group 1 source is also subject to the
Acid Rain Program, TR NOX Annual
Trading Program, or TR NOX Ozone
Season Trading Program, then this
natural person shall be the same natural
person as the alternate designated
representative, as defined in the
respective program.
Assurance account means an
Allowance Management System
account, established by the
Administrator under § 97.625(b)(3) for
certain owners and operators of a group
of one or more TR SO2 Group 1 sources
and units in a given State (and Indian
country within the borders of such
State), in which are held TR SO2 Group
1 allowances available for use for a
control period in a given year in
complying with the TR SO2 Group 1
assurance provisions in accordance with
§§ 97.606 and 97.625.
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48433
Authorized account representative
means, for a general account, the natural
person who is authorized, in accordance
with this subpart, to transfer and
otherwise dispose of TR SO2 Group 1
allowances held in the general account
and, for a TR SO2 Group 1 source’s
compliance account, the designated
representative of the source.
Automated data acquisition and
handling system or DAHS means the
component of the continuous emission
monitoring system, or other emissions
monitoring system approved for use
under this subpart, designed to interpret
and convert individual output signals
from pollutant concentration monitors,
flow monitors, diluent gas monitors,
and other component parts of the
monitoring system to produce a
continuous record of the measured
parameters in the measurement units
required by this subpart.
Biomass means—
(1) Any organic material grown for the
purpose of being converted to energy;
(2) Any organic byproduct of
agriculture that can be converted into
energy; or
(3) Any material that can be converted
into energy and is nonmerchantable for
other purposes, that is segregated from
other material that is nonmerchantable
for other purposes, and that is;
(i) A forest-related organic resource,
including mill residues, precommercial
thinnings, slash, brush, or byproduct
from conversion of trees to
merchantable material; or
(ii) A wood material, including
pallets, crates, dunnage, manufacturing
and construction materials (other than
pressure-treated, chemically-treated, or
painted wood products), and landscape
or right-of-way tree trimmings.
Boiler means an enclosed fossil- or
other-fuel-fired combustion device used
to produce heat and to transfer heat to
recirculating water, steam, or other
medium.
Bottoming-cycle unit means a unit in
which the energy input to the unit is
first used to produce useful thermal
energy, where at least some of the reject
heat from the useful thermal energy
application or process is then used for
electricity production.
Business day means a day that does
not fall on a weekend or a federal
holiday.
Certifying official means a natural
person who is:
(1) For a corporation, a president,
secretary, treasurer, or vice-president of
the corporation in charge of a principal
business function or any other person
who performs similar policy- or
decision-making functions for the
corporation;
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(2) For a partnership or sole
proprietorship, a general partner or the
proprietor respectively; or
(3) For a local government entity or
State, federal, or other public agency, a
principal executive officer or ranking
elected official.
Clean Air Act means the Clean Air
Act, 42 U.S.C. 7401, et seq.
Coal means ‘‘coal’’ as defined in
§ 72.2 of this chapter.
Coal-derived fuel means any fuel
(whether in a solid, liquid, or gaseous
state) produced by the mechanical,
thermal, or chemical processing of coal.
Cogeneration system means an
integrated group, at a source, of
equipment (including a boiler, or
combustion turbine, and a steam turbine
generator) designed to produce useful
thermal energy for industrial,
commercial, heating, or cooling
purposes and electricity through the
sequential use of energy.
Cogeneration unit means a stationary,
fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine that
is a topping-cycle unit or a bottomingcycle unit:
(1) Operating as part of a cogeneration
system; and
(2) Producing on an annual average
basis—
(i) For a topping-cycle unit,
(A) Useful thermal energy not less
than 5 percent of total energy output;
and
(B) Useful power that, when added to
one-half of useful thermal energy
produced, is not less than 42.5 percent
of total energy input, if useful thermal
energy produced is 15 percent or more
of total energy output, or not less than
45 percent of total energy input, if
useful thermal energy produced is less
than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful
power not less than 45 percent of total
energy input;
(3) Provided that the requirements in
paragraph (2) of this definition shall not
apply to a calendar year referenced in
paragraph (2) of this definition during
which the unit did not operate at all;
(4) Provided that the total energy
input under paragraphs (2)(i)(B) and
(2)(ii) of this definition shall equal the
unit’s total energy input from all fuel,
except biomass if the unit is a boiler;
and
(5) Provided that, if, throughout its
operation during the 12-month period or
a calendar year referenced in paragraph
(2) of this definition, a unit is operated
as part of a cogeneration system and the
cogeneration system meets on a systemwide basis the requirement in paragraph
(2)(i)(B) or (2)(ii) of this definition, the
unit shall be deemed to meet such
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requirement during that 12-month
period or calendar year.
Combustion turbine means an
enclosed device comprising:
(1) If the device is simple cycle, a
compressor, a combustor, and a turbine
and in which the flue gas resulting from
the combustion of fuel in the combustor
passes through the turbine, rotating the
turbine; and
(2) If the device is combined cycle,
the equipment described in paragraph
(1) of this definition and any associated
duct burner, heat recovery steam
generator, and steam turbine.
Commence commercial operation
means, with regard to a unit:
(1) To have begun to produce steam,
gas, or other heated medium used to
generate electricity for sale or use,
including test generation, except as
provided in § 97.605.
(i) For a unit that is a TR SO2 Group
1 unit under § 97.604 on the later of
January 1, 2005 or the date the unit
commences commercial operation as
defined in the introductory text of
paragraph (1) of this definition and that
subsequently undergoes a physical
change or is moved to a new location or
source, such date shall remain the date
of commencement of commercial
operation of the unit, which shall
continue to be treated as the same unit.
(ii) For a unit that is a TR SO2 Group
1 unit under § 97.604 on the later of
January 1, 2005 or the date the unit
commences commercial operation as
defined in the introductory text of
paragraph (1) of this definition and that
is subsequently replaced by a unit at the
same or a different source, such date
shall remain the replaced unit’s date of
commencement of commercial
operation, and the replacement unit
shall be treated as a separate unit with
a separate date for commencement of
commercial operation as defined in
paragraph (1) or (2) of this definition as
appropriate.
(2) Notwithstanding paragraph (1) of
this definition and except as provided
in § 97.605, for a unit that is not a TR
SO2 Group 1 unit under § 97.604 on the
later of January 1, 2005 or the date the
unit commences commercial operation
as defined in introductory text of
paragraph (1) of this definition, the
unit’s date for commencement of
commercial operation shall be the date
on which the unit becomes a TR SO2
Group 1 unit under § 97.604.
(i) For a unit with a date for
commencement of commercial
operation as defined in the introductory
text of paragraph (2) of this definition
and that subsequently undergoes a
physical change or is moved to a
different location or source, such date
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shall remain the date of commencement
of commercial operation of the unit,
which shall continue to be treated as the
same unit.
(ii) For a unit with a date for
commencement of commercial
operation as defined in the introductory
text of paragraph (2) of this definition
and that is subsequently replaced by a
unit at the same or a different source,
such date shall remain the replaced
unit’s date of commencement of
commercial operation, and the
replacement unit shall be treated as a
separate unit with a separate date for
commencement of commercial
operation as defined in paragraph (1) or
(2) of this definition as appropriate.
Common designated representative
means, with regard to a control period
in a given year, a designated
representative where, as of April 1
immediately after the allowance transfer
deadline for such control period, the
same natural person is authorized under
§§ 97.613(a) and 97.615(a) as the
designated representative for a group of
one or more TR SO2 Group 1 sources
and units located in a State (and Indian
country within the borders of such
State).
Common designated representative’s
assurance level means, with regard to a
specific common designated
representative and a State (and Indian
country within the borders of such
State) and control period in a given year
for which the State assurance level is
exceeded as described in
§ 97.606(c)(2)(iii), the common
designated representative’s share of the
State SO2 Group 1 trading budget with
the variability limit for the State for
such control period.
Common designated representative’s
share means, with regard to a specific
common designated representative for a
control period in a given year:
(1) With regard to a total amount of
SO2 emissions from all TR SO2 Group 1
units in a State (and Indian country
within the borders of such State) during
such control period, the total tonnage of
SO2 emissions during such control
period from a group of one or more TR
SO2 Group 1 units located in such State
(and such Indian country) and having
the common designated representative
for such control period;
(2) With regard to a State SO2 Group
1 trading budget with the variability
limit for such control period, the
amount (rounded to the nearest
allowance) equal to the sum of the total
amount of TR SO2 Group 1 allowances
allocated for such control period to a
group of one or more TR SO2 Group 1
units located in the State (and Indian
country within the borders of such
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State) and having the common
designated representative for such
control period and of the total amount
of TR SO2 Group 1 allowances
purchased by an owner or operator of
such TR SO2 Group 1 units in an
auction for such control period and
submitted by the State or the permitting
authority to the Administrator for
recordation in the compliance accounts
for such TR SO2 Group 1 units in
accordance with the TR SO2 Group 1
allowance auction provisions in a SIP
revision approved by the Administrator
under § 52.39(e) or (f) of this chapter,
multiplied by the sum of the State SO2
Group 1 trading budget under
§ 97.610(a) and the State’s variability
limit under § 97.610(b) for such control
period and divided by such State SO2
Group 1 trading budget;
(3) Provided that, in the case of a unit
that operates during, but has no amount
of TR SO2 Group 1 allowances allocated
under §§ 97.611 and 97.612 for, such
control period, the unit shall be treated,
solely for purposes of this definition, as
being allocated an amount (rounded to
the nearest allowance) of TR SO2 Group
1 allowances for such control period
equal to the unit’s allowable SO2
emission rate applicable to such control
period, multiplied by a capacity factor
of 0.85 (if the unit is a boiler combusting
any amount of coal or coal-derived fuel
during such control period), 0.24 (if the
unit is a simple combustion turbine
during such control period), 0.67 (if the
unit is a combined cycle turbine during
such control period), 0.74 (if the unit is
an integrated coal gasification combined
cycle unit during such control period),
or 0.36 (for any other unit), multiplied
by the unit’s maximum hourly load as
reported in accordance with this subpart
and by 8,760 hours/control period, and
divided by 2,000 lb/ton.
Common stack means a single flue
through which emissions from 2 or
more units are exhausted.
Compliance account means an
Allowance Management System
account, established by the
Administrator for a TR SO2 Group 1
source under this subpart, in which any
TR SO2 Group 1 allowance allocations
to the TR SO2 Group 1 units at the
source are recorded and in which are
held any TR SO2 Group 1 allowances
available for use for a control period in
a given year in complying with the
source’s TR SO2 Group 1 emissions
limitation in accordance with §§ 97.606
and 97.624.
Continuous emission monitoring
system or CEMS means the equipment
required under this subpart to sample,
analyze, measure, and provide, by
means of readings recorded at least once
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every 15 minutes and using an
automated data acquisition and
handling system (DAHS), a permanent
record of SO2 emissions, stack gas
volumetric flow rate, stack gas moisture
content, and O2 or CO2 concentration (as
applicable), in a manner consistent with
part 75 of this chapter and §§ 97.630
through 97.635. The following systems
are the principal types of continuous
emission monitoring systems:
(1) A flow monitoring system,
consisting of a stack flow rate monitor
and an automated data acquisition and
handling system and providing a
permanent, continuous record of stack
gas volumetric flow rate, in standard
cubic feet per hour (scfh);
(2) A SO2 monitoring system,
consisting of a SO2 pollutant
concentration monitor and an
automated data acquisition and
handling system and providing a
permanent, continuous record of SO2
emissions, in parts per million (ppm);
(3) A moisture monitoring system, as
defined in § 75.11(b)(2) of this chapter
and providing a permanent, continuous
record of the stack gas moisture content,
in percent H2O;
(4) A CO2 monitoring system,
consisting of a CO2 pollutant
concentration monitor (or an O2 monitor
plus suitable mathematical equations
from which the CO2 concentration is
derived) and an automated data
acquisition and handling system and
providing a permanent, continuous
record of CO2 emissions, in percent CO2;
and
(5) An O2 monitoring system,
consisting of an O2 concentration
monitor and an automated data
acquisition and handling system and
providing a permanent, continuous
record of O2, in percent O2.
Control period means the period
starting January 1 of a calendar year,
except as provided in § 97.606(c)(3), and
ending on December 31 of the same
year, inclusive.
Designated representative means, for
a TR SO2 Group 1 source and each TR
SO2 Group 1 unit at the source, the
natural person who is authorized by the
owners and operators of the source and
all such units at the source, in
accordance with this subpart, to
represent and legally bind each owner
and operator in matters pertaining to the
TR SO2 Group 1 Trading Program. If the
TR SO2 Group 1 source is also subject
to the Acid Rain Program, TR NOX
Annual Trading Program, or TR NOX
Ozone Season Trading Program, then
this natural person shall be the same
natural person as the designated
representative, as defined in the
respective program.
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Emissions means air pollutants
exhausted from a unit or source into the
atmosphere, as measured, recorded, and
reported to the Administrator by the
designated representative, and as
modified by the Administrator:
(1) In accordance with this subpart;
and
(2) With regard to a period before the
unit or source is required to measure,
record, and report such air pollutants in
accordance with this subpart, in
accordance with part 75 of this chapter.
Excess emissions means any ton of
emissions from the TR SO2 Group 1
units at a TR SO2 Group 1 source during
a control period in a given year that
exceeds the TR SO2 Group 1 emissions
limitation for the source for such control
period.
Fossil fuel means—
(1) Natural gas, petroleum, coal, or
any form of solid, liquid, or gaseous fuel
derived from such material; or
(2) For purposes of applying the
limitation on ‘‘average annual fuel
consumption of fossil fuel’’ in
§§ 97.604(b)(2)(i)(B) and (ii), natural gas,
petroleum, coal, or any form of solid,
liquid, or gaseous fuel derived from
such material for the purpose of creating
useful heat.
Fossil-fuel-fired means, with regard to
a unit, combusting any amount of fossil
fuel in 2005 or any calendar year
thereafter.
General account means an Allowance
Management System account,
established under this subpart, that is
not a compliance account or an
assurance account.
Generator means a device that
produces electricity.
Gross electrical output means, for a
unit, electricity made available for use,
including any such electricity used in
the power production process (which
process includes, but is not limited to,
any on-site processing or treatment of
fuel combusted at the unit and any onsite emission controls).
Heat input means, for a unit for a
specified period of time, the product (in
mmBtu/time) of the gross calorific value
of the fuel (in mmBtu/lb) fed into the
unit multiplied by the fuel feed rate (in
lb of fuel/time), as measured, recorded,
and reported to the Administrator by the
designated representative and as
modified by the Administrator in
accordance with this subpart and
excluding the heat derived from
preheated combustion air, recirculated
flue gases, or exhaust.
Heat input rate means, for a unit, the
amount of heat input (in mmBtu)
divided by unit operating time (in hr)
or, for a unit and a specific fuel, the
amount of heat input attributed to the
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fuel (in mmBtu) divided by the unit
operating time (in hr) during which the
unit combusts the fuel.
Heat rate means, for a unit, the unit’s
maximum design heat input (in Btu/hr),
divided by the product of 1,000,000
Btu/mmBtu and the unit’s maximum
hourly load.
Indian country means ‘‘Indian
country’’ as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power
contractual arrangement means a unit
participation power sales agreement
under which a utility or industrial
customer reserves, or is entitled to
receive, a specified amount or
percentage of nameplate capacity and
associated energy generated by any
specified unit and pays its proportional
amount of such unit’s total costs,
pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less
than 30 years, including contracts that
permit an election for early termination;
or
(3) For a period no less than 25 years
or 70 percent of the economic useful life
of the unit determined as of the time the
unit is built, with option rights to
purchase or release some portion of the
nameplate capacity and associated
energy generated by the unit at the end
of the period.
Maximum design heat input means,
for a unit, the maximum amount of fuel
per hour (in Btu/hr) that the unit is
capable of combusting on a steady state
basis as of the initial installation of the
unit as specified by the manufacturer of
the unit.
Monitoring system means any
monitoring system that meets the
requirements of this subpart, including
a continuous emission monitoring
system, an alternative monitoring
system, or an excepted monitoring
system under part 75 of this chapter.
Nameplate capacity means, starting
from the initial installation of a
generator, the maximum electrical
generating output (in MWe, rounded to
the nearest tenth) that the generator is
capable of producing on a steady state
basis and during continuous operation
(when not restricted by seasonal or
other deratings) as of such installation
as specified by the manufacturer of the
generator or, starting from the
completion of any subsequent physical
change in the generator resulting in an
increase in the maximum electrical
generating output that the generator is
capable of producing on a steady state
basis and during continuous operation
(when not restricted by seasonal or
other deratings), such increased
maximum amount (in MWe, rounded to
the nearest tenth) as of such completion
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as specified by the person conducting
the physical change.
Natural gas means ‘‘natural gas’’ as
defined in § 72.2 of this chapter.
Newly affected TR SO2 Group 1 unit
means a unit that was not a TR SO2
Group 1 unit when it began operating
but that thereafter becomes a TR SO2
Group 1 unit.
Operate or operation means, with
regard to a unit, to combust fuel.
Operator means, for a TR SO2 Group
1 source or a TR SO2 Group 1 unit at
a source respectively, any person who
operates, controls, or supervises a TR
SO2 Group 1 unit at the source or the
TR SO2 Group 1 unit and shall include,
but not be limited to, any holding
company, utility system, or plant
manager of such source or unit.
Owner means, for a TR SO2 Group 1
source or a TR SO2 Group 1 unit at a
source respectively, any of the following
persons:
(1) Any holder of any portion of the
legal or equitable title in a TR SO2
Group 1 unit at the source or the TR SO2
Group 1 unit;
(2) Any holder of a leasehold interest
in a TR SO2 Group 1 unit at the source
or the TR SO2 Group 1 unit, provided
that, unless expressly provided for in a
leasehold agreement, ‘‘owner’’ shall not
include a passive lessor, or a person
who has an equitable interest through
such lessor, whose rental payments are
not based (either directly or indirectly)
on the revenues or income from such TR
SO2 Group 1 unit; and
(3) Any purchaser of power from a TR
SO2 Group 1 unit at the source or the
TR SO2 Group 1 unit under a life-of-theunit, firm power contractual
arrangement.
Permanently retired means, with
regard to a unit, a unit that is
unavailable for service and that the
unit’s owners and operators do not
expect to return to service in the future.
Permitting authority means
‘‘permitting authority’’ as defined in
§§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity
means, for a unit, 33 percent of the
unit’s maximum design heat input,
divided by 3,413 Btu/kWh, divided by
1,000 kWh/MWh, and multiplied by
8,760 hr/yr.
Receive or receipt of means, when
referring to the Administrator, to come
into possession of a document,
information, or correspondence
(whether sent in hard copy or by
authorized electronic transmission), as
indicated in an official log, or by a
notation made on the document,
information, or correspondence, by the
Administrator in the regular course of
business.
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Recordation, record, or recorded
means, with regard to TR SO2 Group 1
allowances, the moving of TR SO2
Group 1 allowances by the
Administrator into, out of, or between
Allowance Management System
accounts, for purposes of allocation,
auction, transfer, or deduction.
Reference method means any direct
test method of sampling and analyzing
for an air pollutant as specified in
§ 75.22 of this chapter.
Replacement, replace, or replaced
means, with regard to a unit, the
demolishing of a unit, or the permanent
retirement and permanent disabling of a
unit, and the construction of another
unit (the replacement unit) to be used
instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from
electricity production in a useful
thermal energy application or process;
or
(2) The use of reject heat from useful
thermal energy application or process in
electricity production.
Serial number means, for a TR SO2
Group 1 allowance, the unique
identification number assigned to each
TR SO2 Group 1 allowance by the
Administrator.
Solid waste incineration unit means a
stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion
turbine that is a ‘‘solid waste
incineration unit’’ as defined in section
129(g)(1) of the Clean Air Act.
Source means all buildings,
structures, or installations located in
one or more contiguous or adjacent
properties under common control of the
same person or persons. This definition
does not change or otherwise affect the
definition of ‘‘major source’’, ‘‘stationary
source’’, or ‘‘source’’ as set forth and
implemented in a title V operating
permit program or any other program
under the Clean Air Act.
State means one of the States that is
subject to the TR SO2 Group 1 Trading
Program pursuant to § 52.39(a), (b), (d),
(e), and (f) of this chapter.
Submit or serve means to send or
transmit a document, information, or
correspondence to the person specified
in accordance with the applicable
regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or
transmission and delivery;
(4) Provided that compliance with any
‘‘submission’’ or ‘‘service’’ deadline
shall be determined by the date of
dispatch, transmission, or mailing and
not the date of receipt.
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Topping-cycle unit means a unit in
which the energy input to the unit is
first used to produce useful power,
including electricity, where at least
some of the reject heat from the
electricity production is then used to
provide useful thermal energy.
Total energy input means, for a unit,
total energy of all forms supplied to the
unit, excluding energy produced by the
unit. Each form of energy supplied shall
be measured by the lower heating value
of that form of energy calculated as
follows:
LHV = HHV ¥ 10.55(W + 9H)
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Where:
LHV = lower heating value of the form of
energy in Btu/lb,
HHV = higher heating value of the form of
energy in Btu/lb,
W = weight % of moisture in the form of
energy, and
H = weight % of hydrogen in the form of
energy.
Total energy output means, for a unit,
the sum of useful power and useful
thermal energy produced by the unit.
TR NOX Annual Trading Program
means a multi-state NOX air pollution
control and emission reduction program
established in accordance with subpart
AAAAA of this part and § 52.38(a) of
this chapter (including such a program
that is revised in a SIP revision
approved by the Administrator under
§ 52.38(a)(3) or (4) of this chapter or that
is established in a SIP revision approved
by the Administrator under § 52.38(a)(5)
of this chapter), as a means of mitigating
interstate transport of fine particulates
and NOX.
TR NOX Ozone Season Trading
Program means a multi-state NOX air
pollution control and emission
reduction program established in
accordance with subpart BBBBB of this
part and § 52.38(b) of this chapter
(including such a program that is
revised in a SIP revision approved by
the Administrator under § 52.38(b)(3) or
(4) of this chapter or that is established
in a SIP revision approved by the
Administrator under § 52.38(b)(5) of this
chapter), as a means of mitigating
interstate transport of ozone and NOX.
TR SO2 Group 1 allowance means a
limited authorization issued and
allocated or auctioned by the
Administrator under this subpart, or by
a State or permitting authority under a
SIP revision approved by the
Administrator under § 52.39(d), (e), or
(f) of this chapter, to emit one ton of SO2
during a control period of the specified
calendar year for which the
authorization is allocated or auctioned
or of any calendar year thereafter under
the TR SO2 Group 1 Trading Program.
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TR SO2 Group 1 allowance deduction
or deduct TR SO2 Group 1 allowances
means the permanent withdrawal of TR
SO2 Group 1 allowances by the
Administrator from a compliance
account (e.g., in order to account for
compliance with the TR SO2 Group 1
emissions limitation) or from an
assurance account (e.g., in order to
account for compliance with the
assurance provisions under §§ 97.606
and 97.625).
TR SO2 Group 1 allowances held or
hold TR SO2 Group 1 allowances means
the TR SO2 Group 1 allowances treated
as included in an Allowance
Management System account as of a
specified point in time because at that
time they:
(1) Have been recorded by the
Administrator in the account or
transferred into the account by a
correctly submitted, but not yet
recorded, TR SO2 Group 1 allowance
transfer in accordance with this subpart;
and
(2) Have not been transferred out of
the account by a correctly submitted,
but not yet recorded, TR SO2 Group 1
allowance transfer in accordance with
this subpart.
TR SO2 Group 1 emissions limitation
means, for a TR SO2 Group 1 source, the
tonnage of SO2 emissions authorized in
a control period by the TR SO2 Group
1 allowances available for deduction for
the source under § 97.624(a) for such
control period.
TR SO2 Group 1 source means a
source that includes one or more TR
SO2 Group 1 units.
TR SO2 Group 1 Trading Program
means a multi-state SO2 air pollution
control and emission reduction program
established in accordance with this
subpart and § 52.39(a), (b), (d) through
(f), (j), and (k) of this chapter (including
such a program that is revised in a SIP
revision approved by the Administrator
under § 52.39(d) or (e) of this chapter or
that is established in a SIP revision
approved by the Administrator under
§ 52.39(f) of this chapter), as a means of
mitigating interstate transport of fine
particulates and SO2.
TR SO2 Group 1 unit means a unit
that is subject to the TR SO2 Group 1
Trading Program under § 97.604.
Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired
combustion turbine, or other stationary,
fossil-fuel-fired combustion device. A
unit that undergoes a physical change or
is moved to a different location or
source shall continue to be treated as
the same unit. A unit (the replaced unit)
that is replaced by another unit (the
replacement unit) at the same or a
different source shall continue to be
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48437
treated as the same unit, and the
replacement unit shall be treated as a
separate unit.
Unit operating day means, with
regard to a unit, a calendar day in which
the unit combusts any fuel.
Unit operating hour or hour of unit
operation means, with regard to a unit,
an hour in which the unit combusts any
fuel.
Useful power means, with regard to a
unit, electricity or mechanical energy
that the unit makes available for use,
excluding any such energy used in the
power production process (which
process includes, but is not limited to,
any on-site processing or treatment of
fuel combusted at the unit and any onsite emission controls).
Useful thermal energy means thermal
energy that is:
(1) Made available to an industrial or
commercial process (not a power
production process), excluding any heat
contained in condensate return or
makeup water;
(2) Used in a heating application (e.g.,
space heating or domestic hot water
heating); or
(3) Used in a space cooling
application (i.e., in an absorption
chiller).
Utility power distribution system
means the portion of an electricity grid
owned or operated by a utility and
dedicated to delivering electricity to
customers.
§ 97.603 Measurements, abbreviations,
and acronyms.
Measurements, abbreviations, and
acronyms used in this subpart are
defined as follows:
Btu—British thermal unit
CO2—carbon dioxide
H2O—water
hr—hour
kW—kilowatt electrical
kWh—kilowatt hour
lb—pound
mmBtu—million Btu
MWe—megawatt electrical
MWh—megawatt hour
NOX—nitrogen oxides
O2—oxygen
ppm—parts per million
scfh—standard cubic feet per hour
SO2—sulfur dioxide
yr—year
§ 97.604
Applicability.
(a) Except as provided in paragraph
(b) of this section:
(1) The following units in a State (and
Indian country within the borders of
such State) shall be TR SO2 Group 1
units, and any source that includes one
or more such units shall be a TR SO2
Group 1 source, subject to the
requirements of this subpart: any
stationary, fossil-fuel-fired boiler or
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stationary, fossil-fuel-fired combustion
turbine serving at any time, on or after
January 1, 2005, a generator with
nameplate capacity of more than 25
MWe producing electricity for sale.
(2) If a stationary boiler or stationary
combustion turbine that, under
paragraph (a)(1) of this section, is not a
TR SO2 Group 1 unit begins to combust
fossil fuel or to serve a generator with
nameplate capacity of more than 25
MWe producing electricity for sale, the
unit shall become a TR SO2 Group 1
unit as provided in paragraph (a)(1) of
this section on the first date on which
it both combusts fossil fuel and serves
such generator.
(b) Any unit in a State (and Indian
country within the borders of such
State) that otherwise is a TR SO2 Group
1 unit under paragraph (a) of this
section and that meets the requirements
set forth in paragraph (b)(1)(i) or (2)(i) of
this section shall not be a TR SO2 Group
1 unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit
throughout the later of 2005 or the 12month period starting on the date the
unit first produces electricity and
continuing to qualify as a cogeneration
unit throughout each calendar year
ending after the later of 2005 or such 12month period; and
(B) Not supplying in 2005 or any
calendar year thereafter more than onethird of the unit’s potential electric
output capacity or 219,000 MWh,
whichever is greater, to any utility
power distribution system for sale.
(ii) If, after qualifying under
paragraph (b)(1)(i) of this section as not
being a TR SO2 Group 1 unit, a unit
subsequently no longer meets all the
requirements of paragraph (b)(1)(i) of
this section, the unit shall become a TR
SO2 Group 1 unit starting on the earlier
of January 1 after the first calendar year
during which the unit first no longer
qualifies as a cogeneration unit or
January 1 after the first calendar year
during which the unit no longer meets
the requirements of paragraph
(b)(1)(i)(B) of this section. The unit shall
thereafter continue to be a TR SO2
Group 1 unit.
(2)(i) Any unit:
(A) Qualifying as a solid waste
incineration unit throughout the later of
2005 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit
throughout each calendar year ending
after the later of 2005 or such 12-month
period; and
(B) With an average annual fuel
consumption of fossil fuel for the first
3 consecutive calendar years of
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operation starting no earlier than 2005
of less than 20 percent (on a Btu basis)
and an average annual fuel consumption
of fossil fuel for any 3 consecutive
calendar years thereafter of less than 20
percent (on a Btu basis).
(ii) If, after qualifying under
paragraph (b)(2)(i) of this section as not
being a TR SO2 Group 1 unit, a unit
subsequently no longer meets all the
requirements of paragraph (b)(1)(i) of
this section, the unit shall become a TR
SO2 Group 1 unit starting on the earlier
of January 1 after the first calendar year
during which the unit first no longer
qualifies as a solid waste incineration
unit or January 1 after the first 3
consecutive calendar years after 2005
for which the unit has an average
annual fuel consumption of fossil fuel of
20 percent or more. The unit shall
thereafter continue to be a TR SO2
Group 1 unit.
(c) A certifying official of an owner or
operator of any unit or other equipment
may submit a petition (including any
supporting documents) to the
Administrator at any time for a
determination concerning the
applicability, under paragraphs (a) and
(b) of this section or a SIP revision
approved under § 52.39(e) or (f) of this
chapter, of the TR SO2 Group 1 Trading
Program to the unit or other equipment.
(1) Petition content. The petition shall
be in writing and include the
identification of the unit or other
equipment and the relevant facts about
the unit or other equipment. The
petition and any other documents
provided to the Administrator in
connection with the petition shall
include the following certification
statement, signed by the certifying
official: ‘‘I am authorized to make this
submission on behalf of the owners and
operators of the unit or other equipment
for which the submission is made. I
certify under penalty of law that I have
personally examined, and am familiar
with, the statements and information
submitted in this document and all its
attachments. Based on my inquiry of
those individuals with primary
responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(2) Response. The Administrator will
issue a written response to the petition
and may request supplemental
information determined by the
Administrator to be relevant to such
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petition. The Administrator’s
determination concerning the
applicability, under paragraphs (a) and
(b) of this section, of the TR SO2 Group
1 Trading Program to the unit or other
equipment shall be binding on any State
or permitting authority unless the
Administrator determines that the
petition or other documents or
information provided in connection
with the petition contained significant,
relevant errors or omissions.
§ 97.605
Retired unit exemption.
(a)(1) Any TR SO2 Group 1 unit that
is permanently retired shall be exempt
from § 97.606(b) and (c)(1), § 97.624,
and §§ 97.630 through 97.635.
(2) The exemption under paragraph
(a)(1) of this section shall become
effective the day on which the TR SO2
Group 1 unit is permanently retired.
Within 30 days of the unit’s permanent
retirement, the designated
representative shall submit a statement
to the Administrator. The statement
shall state, in a format prescribed by the
Administrator, that the unit was
permanently retired on a specified date
and will comply with the requirements
of paragraph (b) of this section.
(b) Special provisions. (1) A unit
exempt under paragraph (a) of this
section shall not emit any SO2, starting
on the date that the exemption takes
effect.
(2) For a period of 5 years from the
date the records are created, the owners
and operators of a unit exempt under
paragraph (a) of this section shall retain,
at the source that includes the unit,
records demonstrating that the unit is
permanently retired. The 5-year period
for keeping records may be extended for
cause, at any time before the end of the
period, in writing by the Administrator.
The owners and operators bear the
burden of proof that the unit is
permanently retired.
(3) The owners and operators and, to
the extent applicable, the designated
representative of a unit exempt under
paragraph (a) of this section shall
comply with the requirements of the TR
SO2 Group 1 Trading Program
concerning all periods for which the
exemption is not in effect, even if such
requirements arise, or must be complied
with, after the exemption takes effect.
(4) A unit exempt under paragraph (a)
of this section shall lose its exemption
on the first date on which the unit
resumes operation. Such unit shall be
treated, for purposes of applying
allocation, monitoring, reporting, and
recordkeeping requirements under this
subpart, as a unit that commences
commercial operation on the first date
on which the unit resumes operation.
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§ 97.606
Standard requirements.
(a) Designated representative
requirements. The owners and operators
shall comply with the requirement to
have a designated representative, and
may have an alternate designated
representative, in accordance with
§§ 97.613 through 97.618.
(b) Emissions monitoring, reporting,
and recordkeeping requirements. (1)
The owners and operators, and the
designated representative, of each TR
SO2 Group 1 source and each TR SO2
Group 1 unit at the source shall comply
with the monitoring, reporting, and
recordkeeping requirements of §§ 97.630
through 97.635.
(2) The emissions data determined in
accordance with §§ 97.630 through
97.635 shall be used to calculate
allocations of TR SO2 Group 1
allowances under §§ 97.611(a)(2) and (b)
and 97.612 and to determine
compliance with the TR SO2 Group 1
emissions limitation and assurance
provisions under paragraph (c) of this
section, provided that, for each
monitoring location from which mass
emissions are reported, the mass
emissions amount used in calculating
such allocations and determining such
compliance shall be the mass emissions
amount for the monitoring location
determined in accordance with
§§ 97.630 through 97.635 and rounded
to the nearest ton, with any fraction of
a ton less than 0.50 being deemed to be
zero.
(c) SO2 emissions requirements. (1)
TR SO2 Group 1 emissions limitation. (i)
As of the allowance transfer deadline for
a control period in a given year, the
owners and operators of each TR SO2
Group 1 source and each TR SO2 Group
1 unit at the source shall hold, in the
source’s compliance account, TR SO2
Group 1 allowances available for
deduction for such control period under
§ 97.624(a) in an amount not less than
the tons of total SO2 emissions for such
control period from all TR SO2 Group 1
units at the source.
(ii) If total SO2 emissions during a
control period in a given year from the
TR SO2 Group 1 units at a TR SO2
Group 1 source are in excess of the TR
SO2 Group 1 emissions limitation set
forth in paragraph (c)(1)(i) of this
section, then:
(A) The owners and operators of the
source and each TR SO2 Group 1 unit
at the source shall hold the TR SO2
Group 1 allowances required for
deduction under § 97.624(d); and
(B) The owners and operators of the
source and each TR SO2 Group 1 unit
at the source shall pay any fine, penalty,
or assessment or comply with any other
remedy imposed, for the same
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violations, under the Clean Air Act, and
each ton of such excess emissions and
each day of such control period shall
constitute a separate violation of this
subpart and the Clean Air Act.
(2) TR SO2 Group 1 assurance
provisions. (i) If total SO2 emissions
during a control period in a given year
from all TR SO2 Group 1 units at TR SO2
Group 1 sources in a State (and Indian
country within the borders of such
State) exceed the State assurance level,
then the owners and operators of such
sources and units in each group of one
or more sources and units having a
common designated representative for
such control period, where the common
designated representative’s share of
such SO2 emissions during such control
period exceeds the common designated
representative’s assurance level for the
State and such control period, shall
hold (in the assurance account
established for the owners and operators
of such group) TR SO2 Group 1
allowances available for deduction for
such control period under § 97.625(a) in
an amount equal to two times the
product (rounded to the nearest whole
number), as determined by the
Administrator in accordance with
§ 97.625(b), of multiplying—
(A) The quotient of the amount by
which the common designated
representative’s share of such SO2
emissions exceeds the common
designated representative’s assurance
level divided by the sum of the
amounts, determined for all common
designated representatives for such
sources and units in the State (and
Indian country within the borders of
such State) for such control period, by
which each common designated
representative’s share of such SO2
emissions exceeds the respective
common designated representative’s
assurance level; and
(B) The amount by which total SO2
emissions from all TR SO2 Group 1
units at TR SO2 Group 1 sources in the
State (and Indian country within the
borders of such State) for such control
period exceed the State assurance level.
(ii) The owners and operators shall
hold the TR SO2 Group 1 allowances
required under paragraph (c)(2)(i) of this
section, as of midnight of November 1
(if it is a business day), or midnight of
the first business day thereafter (if
November 1 is not a business day),
immediately after such control period.
(iii) Total SO2 emissions from all TR
SO2 Group 1 units at TR SO2 Group 1
sources in a State (and Indian country
within the borders of such State) during
a control period in a given year exceed
the State assurance level if such total
SO2 emissions exceed the sum, for such
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48439
control period, of the State SO2 Group
1 trading budget under § 97.610(a) and
the State’s variability limit under
§ 97.610(b).
(iv) It shall not be a violation of this
subpart or of the Clean Air Act if total
SO2 emissions from all TR SO2 Group 1
units at TR SO2 Group 1 sources in a
State (and Indian country within the
borders of such State) during a control
period exceed the State assurance level
or if a common designated
representative’s share of total SO2
emissions from the TR SO2 Group 1
units at TR SO2 Group 1 sources in a
State (and Indian country within the
borders of such State) during a control
period exceeds the common designated
representative’s assurance level.
(v) To the extent the owners and
operators fail to hold TR SO2 Group 1
allowances for a control period in a
given year in accordance with
paragraphs (c)(2)(i) through (iii) of this
section,
(A) The owners and operators shall
pay any fine, penalty, or assessment or
comply with any other remedy imposed
under the Clean Air Act; and
(B) Each TR SO2 Group 1 allowance
that the owners and operators fail to
hold for such control period in
accordance with paragraphs (c)(2)(i)
through (iii) of this section and each day
of such control period shall constitute a
separate violation of this subpart and
the Clean Air Act.
(3) Compliance periods. A TR SO2
Group 1 unit shall be subject to the
requirements under paragraphs (c)(1)
and (c)(2) of this section for the control
period starting on the later of January 1,
2012 or the deadline for meeting the
unit’s monitor certification
requirements under § 97.630(b) and for
each control period thereafter.
(4) Vintage of allowances held for
compliance. (i) A TR SO2 Group 1
allowance held for compliance with the
requirements under paragraph (c)(1)(i)
of this section for a control period in a
given year must be a TR SO2 Group 1
allowance that was allocated for such
control period or a control period in a
prior year.
(ii) A TR SO2 Group 1 allowance held
for compliance with the requirements
under paragraphs (c)(1)(ii)(A) and (2)(i)
through (iii) of this section for a control
period in a given year must be a TR SO2
Group 1 allowance that was allocated
for a control period in a prior year or the
control period in the given year or in the
immediately following year.
(5) Allowance Management System
requirements. Each TR SO2 Group 1
allowance shall be held in, deducted
from, or transferred into, out of, or
between Allowance Management
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System accounts in accordance with
this subpart.
(6) Limited authorization. A TR SO2
Group 1 allowance is a limited
authorization to emit one ton of SO2
during the control period in one year.
Such authorization is limited in its use
and duration as follows:
(i) Such authorization shall only be
used in accordance with the TR SO2
Group 1 Trading Program; and
(ii) Notwithstanding any other
provision of this subpart, the
Administrator has the authority to
terminate or limit the use and duration
of such authorization to the extent the
Administrator determines is necessary
or appropriate to implement any
provision of the Clean Air Act.
(7) Property right. A TR SO2 Group 1
allowance does not constitute a property
right.
(d) Title V permit requirements. (1) No
title V permit revision shall be required
for any allocation, holding, deduction,
or transfer of TR SO2 Group 1
allowances in accordance with this
subpart.
(2) A description of whether a unit is
required to monitor and report SO2
emissions using a continuous emission
monitoring system (under subpart H of
part 75 of this chapter), an excepted
monitoring system (under appendices D
and E to part 75 of this chapter), a low
mass emissions excepted monitoring
methodology (under § 75.19 of this
chapter), or an alternative monitoring
system (under subpart E of part 75 of
this chapter) in accordance with
§§ 97.630 through 97.635 may be added
to, or changed in, a title V permit using
minor permit modification procedures
in accordance with §§ 70.7(e)(2) and
71.7(e)(1) of this chapter, provided that
the requirements applicable to the
described monitoring and reporting (as
added or changed, respectively) are
already incorporated in such permit.
This paragraph explicitly provides that
the addition of, or change to, a unit’s
description as described in the prior
sentence is eligible for minor permit
modification procedures in accordance
with §§ 70.7(e)(2)(i)(B) and
71.7(e)(1)(i)(B) of this chapter.
(e) Additional recordkeeping and
reporting requirements. (1) Unless
otherwise provided, the owners and
operators of each TR SO2 Group 1
source and each TR SO2 Group 1 unit
at the source shall keep on site at the
source each of the following documents
(in hardcopy or electronic format) for a
period of 5 years from the date the
document is created. This period may
be extended for cause, at any time
before the end of 5 years, in writing by
the Administrator.
(i) The certificate of representation
under § 97.616 for the designated
representative for the source and each
TR SO2 Group 1 unit at the source and
all documents that demonstrate the
truth of the statements in the certificate
of representation; provided that the
certificate and documents shall be
retained on site at the source beyond
such 5-year period until such certificate
of representation and documents are
superseded because of the submission of
a new certificate of representation under
§ 97.616 changing the designated
representative.
(ii) All emissions monitoring
information, in accordance with this
subpart.
(iii) Copies of all reports, compliance
certifications, and other submissions
and all records made or required under,
or to demonstrate compliance with the
requirements of, the TR SO2 Group 1
Trading Program.
(2) The designated representative of a
TR SO2 Group 1 source and each TR
SO2 Group 1 unit at the source shall
make all submissions required under
the TR SO2 Group 1 Trading Program,
except as provided in § 97.618. This
requirement does not change, create an
exemption from, or or otherwise affect
the responsible official submission
requirements under a title V operating
permit program in parts 70 and 71 of
this chapter.
(f) Liability. (1) Any provision of the
TR SO2 Group 1 Trading Program that
applies to a TR SO2 Group 1 source or
the designated representative of a TR
SO2 Group 1 source shall also apply to
the owners and operators of such source
and of the TR SO2 Group 1 units at the
source.
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Jkt 223001
Computation of time.
(a) Unless otherwise stated, any time
period scheduled, under the TR SO2
Group 1 Trading Program, to begin on
the occurrence of an act or event shall
begin on the day the act or event occurs.
(b) Unless otherwise stated, any time
period scheduled, under the TR SO2
Group 1 Trading Program, to begin
before the occurrence of an act or event
shall be computed so that the period
ends the day before the act or event
occurs.
(c) Unless otherwise stated, if the final
day of any time period, under the TR
SO2 Group 1 Trading Program, is not a
business day, the time period shall be
extended to the next business day.
§ 97.608 Administrative appeal
procedures.
The administrative appeal procedures
for decisions of the Administrator under
the TR SO2 Group 1 Trading Program
are set forth in part 78 of this chapter.
§ 97.609
[Reserved]
§ 97.610 State SO2 Group 1 trading
budgets, new unit set-asides, Indian
country new unit set-aside, and variability
limits.
(a) The State SO2 Group 1 trading
budgets, new unit set-asides, and Indian
country new unit set-asides for
allocations of TR SO2 Group 1
allowances for the control periods in
2012 and thereafter are as follows:
New unit set-aside
(tons)
for 2012 and 2013
Indian country new
unit set-aside (tons)
for 2012 and 2013
234,889
285,424
107,085
232,662
30,120
229,303
207,466
5,574
11,744
8,563
2,035
13,960
602
4,357
4,149
111
................................
................................
107
................................
................................
229
................................
................................
Illinois ...................................................................................................................
Indiana .................................................................................................................
Iowa .....................................................................................................................
Kentucky ..............................................................................................................
Maryland ..............................................................................................................
Michigan ...............................................................................................................
Missouri ................................................................................................................
New Jersey ..........................................................................................................
19:20 Aug 05, 2011
§ 97.607
SO2 Group 1 trading budget (tons) *
for 2012 and 2013
State
VerDate Mar<15>2010
(2) Any provision of the TR SO2
Group 1 Trading Program that applies to
a TR SO2 Group 1 unit or the designated
representative of a TR SO2 Group 1 unit
shall also apply to the owners and
operators of such unit.
(g) Effect on other authorities. No
provision of the TR SO2 Group 1
Trading Program or exemption under
§ 97.605 shall be construed as
exempting or excluding the owners and
operators, and the designated
representative, of a TR SO2 Group 1
source or TR SO2 Group 1 unit from
compliance with any other provision of
the applicable, approved State
implementation plan, a federally
enforceable permit, or the Clean Air Act.
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48441
SO2 Group 1 trading budget (tons) *
for 2012 and 2013
New unit set-aside
(tons)
for 2012 and 2013
Indian country new
unit set-aside (tons)
for 2012 and 2013
27,325
136,881
310,230
278,651
148,150
70,820
146,174
79,480
520
10,813
6,205
5,573
2,963
2,833
10,232
3,894
27
137
................................
................................
................................
................................
................................
80
SO2 Group 1 trading budget (tons) *
for 2014 and thereafter
State
New unit set-aside
(tons)
for 2014 and thereafter
Indian country new
unit set-aside (tons)
for 2014 and thereafter
124,123
161,111
75,184
106,284
28,203
143,995
165,941
5,574
18,585
57,620
137,077
112,021
58,833
35,057
75,668
40,126
6,206
4,833
1,429
6,377
564
2,736
3,319
111
353
4,552
2,742
2,240
1,177
1,402
5,297
1,966
................................
................................
75
................................
................................
144
................................
................................
19
58
................................
................................
................................
................................
................................
40
New York .............................................................................................................
North Carolina ......................................................................................................
Ohio .....................................................................................................................
Pennsylvania ........................................................................................................
Tennessee ...........................................................................................................
Virginia .................................................................................................................
West Virginia ........................................................................................................
Wisconsin .............................................................................................................
State
Illinois ...................................................................................................................
Indiana .................................................................................................................
Iowa .....................................................................................................................
Kentucky ..............................................................................................................
Maryland ..............................................................................................................
Michigan ...............................................................................................................
Missouri ................................................................................................................
New Jersey ..........................................................................................................
New York .............................................................................................................
North Carolina ......................................................................................................
Ohio .....................................................................................................................
Pennsylvania ........................................................................................................
Tennessee ...........................................................................................................
Virginia .................................................................................................................
West Virginia ........................................................................................................
Wisconsin .............................................................................................................
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-aside and does not include the
variability limit.
(b) The States’ variability limits for
the State SO2 Group 1 trading budgets
for the control periods in 2012 and
thereafter are as follows:
Variability limits
for 2012 and 2013
State
Variability limits
for 2014 and thereafter
42,280
51,376
19,275
41,879
5,422
41,275
37,344
1,003
4,919
24,639
55,841
50,157
26,667
12,748
26,311
14,306
22,342
29,000
13,533
19,131
5,077
25,919
29,869
1,003
3,345
10,372
24,674
20,164
10,590
6,310
13,620
7,223
Illinois .......................................................................................................................................................
Indiana .....................................................................................................................................................
Iowa .........................................................................................................................................................
Kentucky ..................................................................................................................................................
Maryland ..................................................................................................................................................
Michigan ...................................................................................................................................................
Missouri ....................................................................................................................................................
New Jersey ..............................................................................................................................................
New York .................................................................................................................................................
North Carolina ..........................................................................................................................................
Ohio .........................................................................................................................................................
Pennsylvania ............................................................................................................................................
Tennessee ...............................................................................................................................................
Virginia .....................................................................................................................................................
West Virginia ............................................................................................................................................
Wisconsin .................................................................................................................................................
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§ 97.611 Timing requirements for TR SO2
Group 1 allowance allocations.
(a) Existing units. (1) TR SO2 Group 1
allowances are allocated, for the control
periods in 2012 and each year
thereafter, as provided in a notice of
data availability issued by the
Administrator. Providing an allocation
to a unit in such notice does not
constitute a determination that the unit
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19:20 Aug 05, 2011
Jkt 223001
is a TR SO2 Group 1 unit, and not
providing an allocation to a unit in such
notice does not constitute a
determination that the unit is not a TR
SO2 Group 1 unit.
(2) Notwithstanding paragraph (a)(1)
of this section, if a unit provided an
allocation in the notice of data
availability issued under paragraph
(a)(1) of this section does not operate,
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starting after 2011, during the control
period in two consecutive years, such
unit will not be allocated the TR SO2
Group 1 allowances provided in such
notice for the unit for the control
periods in the fifth year after the first
such year and in each year after that
fifth year. All TR SO2 Group 1
allowances that would otherwise have
been allocated to such unit will be
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allocated to the new unit set-aside for
the State where such unit is located and
for the respective years involved. If such
unit resumes operation, the
Administrator will allocate TR SO2
Group 1 allowances to the unit in
accordance with paragraph (b) of this
section.
(b) New units. (1) New unit set-asides.
(i) By June 1, 2012 and June 1 of each
year thereafter, the Administrator will
calculate the TR SO2 Group 1 allowance
allocation to each TR SO2 Group 1 unit
in a State, in accordance with
§ 97.612(a)(2) through (7) and (12), for
the control period in the year of the
applicable calculation deadline under
this paragraph and will promulgate a
notice of data availability of the results
of the calculations.
(ii) For each notice of data availability
required in paragraph (b)(1)(i) of this
section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(1)(i) of this section and shall be
limited to addressing whether the
calculations (including the
identification of the TR SO2 Group 1
units) are in accordance with
§ 97.612(a)(2) through (7) and (12) and
§§ 97.606(b)(2) and 97.630 through
97.635.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(1)(ii)(A) of this section. By August 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(1)(i) of this section, the
Administrator will promulgate a notice
of data availability of any adjustments
that the Administrator determines to be
necessary with regard to allocations
under § 97.612(a)(2) through (7) and (12)
and the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(1)(ii)(A)
of this section.
(iii) If the new unit set-aside for such
control period contains any TR SO2
Group 1 allowances that have not been
allocated in the applicable notice of data
availability required in paragraph
(b)(1)(ii) of this section, the
Administrator will promulgate, by
December 15 immediately after such
notice, a notice of data availability that
identifies any TR SO2 Group 1 units that
commenced commercial operation
during the period starting January 1 of
the year before the year of such control
period and ending November 30 of year
of such control period.
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19:20 Aug 05, 2011
Jkt 223001
(iv) For each notice of data
availability required in paragraph
(b)(1)(iii) of this section, the
Administrator will provide an
opportunity for submission of objections
to the identification of TR SO2 annual
units in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(1)(iii) of this section and shall be
limited to addressing whether the
identification of TR SO2 annual units in
such notice is in accordance with
paragraph (b)(1)(iii) of this section.
(B) The Administrator will adjust the
identification of TR SO2 Group 1 units
in each notice of data availability
required in paragraph (b)(1)(iii) of this
section to the extent necessary to ensure
that it is in accordance with paragraph
(b)(1)(iii) of this section and will
calculate the TR SO2 Group 1 allowance
allocation to each TR SO2 Group 1 unit
in accordance with § 97.612(a)(9), (10),
and (12) and §§ 97.606(b)(2) and 97.630
through 97.635. By February 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(1)(iii) of this section,
the Administrator will promulgate a
notice of data availability of any
adjustments of the identification of TR
SO2 Group 1 units that the
Administrator determines to be
necessary, the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(1)(iv)(A)
of this section, and the results of such
calculations.
(v) To the extent any TR SO2 Group
1 allowances are added to the new unit
set-aside after promulgation of each
notice of data availability required in
paragraph (b)(1)(iv) of this section, the
Administrator will promulgate
additional notices of data availability, as
deemed appropriate, of the allocation of
such TR SO2 Group 1 allowances in
accordance with § 97.612(a)(10).
(2) Indian country new unit setasides. (i) By June 1, 2012 and June 1
of each year thereafter, the
Administrator will calculate the TR SO2
Group 1 allowance allocation to each TR
SO2 Group 1 unit in Indian country
within the borders of a State, in
accordance with § 97.612(b)(2) through
(7) and (12), for the control period in the
year of the applicable calculation
deadline under this paragraph and will
promulgate a notice of data availability
of the results of the calculations.
(ii) For each notice of data availability
required in paragraph (b)(2)(i) of this
section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
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(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(2)(i) of this section and shall be
limited to addressing whether the
calculations (including the
identification of the TR SO2 Group 1
units) are in accordance with
§ 97.612(b)(2) through (7) and (12) and
§§ 97.606(b)(2) and 97.630 through
97.635.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(2)(ii)(A) of this section. By August 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(i) of this section, the
Administrator will promulgate a notice
of data availability of any adjustments
that the Administrator determines to be
necessary with regard to allocations
under § 97.612(b)(2) through (7) and (12)
and the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(2)(ii)(A)
of this section.
(iii) If the Indian country new unit
set-aside for such control period
contains any TR SO2 Group 1
allowances that have not been allocated
in the applicable notice of data
availability required in paragraph
(b)(2)(ii) of this section, the
Administrator will promulgate, by
December 15 immediately after such
notice, a notice of data availability that
identifies any TR SO2 Group 1 units that
commenced commercial operation
during the period starting January 1 of
the year before the year of such control
period and ending November 30 of year
of such control period.
(iv) For each notice of data
availability required in paragraph
(b)(2)(iii) of this section, the
Administrator will provide an
opportunity for submission of objections
to the identification of TR SO2 annual
units in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(2)(iii) of this section and shall be
limited to addressing whether the
identification of TR SO2 annual units in
such notice is in accordance with
paragraph (b)(2)(iii) of this section.
(B) The Administrator will adjust the
identification of TR SO2 Group 1 units
in each notice of data availability
required in paragraph (b)(2)(iii) of this
section to the extent necessary to ensure
that it is in accordance with paragraph
(b)(2)(iii) of this section and will
calculate the TR SO2 Group 1 allowance
allocation to each TR SO2 Group 1 unit
in accordance with § 97.612(b)(9), (10),
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and (12) and §§ 97.606(b)(2) and 97.630
through 97.635. By February 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(iii) of this section,
the Administrator will promulgate a
notice of data availability of any
adjustments of the identification of TR
SO2 Group 1 units that the
Administrator determines to be
necessary, the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(2)(iv)(A)
of this section, and the results of such
calculations.
(v) To the extent any TR SO2 Group
1 allowances are added to the Indian
country new unit set-aside after
promulgation of each notice of data
availability required in paragraph
(b)(2)(iv) of this section, the
Administrator will promulgate
additional notices of data availability, as
deemed appropriate, of the allocation of
such TR NOX Annual allowances in
accordance with § 97.612(b)(10).
(c) Units incorrectly allocated TR SO2
Group 1 allowances. (1) For each control
period in 2012 and thereafter, if the
Administrator determines that TR SO2
Group 1 allowances were allocated
under paragraph (a) of this section, or
under a provision of a SIP revision
approved under § 52.39(d), (e), or (f) of
this chapter, where such control period
and the recipient are covered by the
provisions of paragraph (c)(1)(i) of this
section or were allocated under
§ 97.612(a)(2) through (7), (9), and (12)
and (b)(2) through (7), (9), and (12), or
under a provision of a SIP revision
approved under § 52.39(e) or (f) of this
chapter, where such control period and
the recipient are covered by the
provisions of paragraph (c)(1)(ii) of this
section, then the Administrator will
notify the designated representative of
the recipient and will act in accordance
with the procedures set forth in
paragraphs (c)(2) through (5) of this
section:
(i)(A) The recipient is not actually a
TR SO2 Group 1 unit under § 97.604 as
of January 1, 2012 and is allocated TR
SO2 Group 1 allowances for such
control period or, in the case of an
allocation under a provision of a SIP
revision approved under § 52.39(d), (e),
or (f) of this chapter, the recipient is not
actually a TR SO2 Group 1 unit as of
January 1, 2012 and is allocated TR SO2
Group 1 allowances for such control
period that the SIP revision provides
should be allocated only to recipients
that are TR SO2 Group 1 units as of
January 1, 2012; or
(B) The recipient is not located as of
January 1 of the control period in the
State from whose SO2 Group 1 trading
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19:20 Aug 05, 2011
Jkt 223001
budget the TR SO2 Group 1 allowances
allocated under paragraph (a) of this
section, or under a provision of a SIP
revision approved under § 52.39(d), (e),
or (f) of this chapter, were allocated for
such control period.
(ii) The recipient is not actually a TR
SO2 Group 1 unit under § 97.604 as of
January 1 of such control period and is
allocated TR SO2 Group 1 allowances
for such control period or, in the case
of an allocation under a provision of a
SIP revision approved under § 52.39(d),
(e), or (f) of this chapter, the recipient
is not actually a TR SO2 Group 1 unit
as of January 1 of such control period
and is allocated TR SO2 Group 1
allowances for such control period that
the SIP revision provides should be
allocated only to recipients that are TR
SO2 Group 1 units as of January 1 of
such control period.
(2) Except as provided in paragraph
(c)(3) or (4) of this section, the
Administrator will not record such TR
SO2 Group 1 allowances under § 97.621.
(3) If the Administrator already
recorded such TR SO2 Group 1
allowances under § 97.621 and if the
Administrator makes the determination
under paragraph (c)(1) of this section
before making deductions for the source
that includes such recipient under
§ 97.624(b) for such control period, then
the Administrator will deduct from the
account in which such TR SO2 Group 1
allowances were recorded an amount of
TR SO2 Group 1 allowances allocated
for the same or a prior control period
equal to the amount of such already
recorded TR SO2 Group 1 allowances.
The authorized account representative
shall ensure that there are sufficient TR
SO2 Group 1 allowances in such
account for completion of the
deduction.
(4) If the Administrator already
recorded such TR SO2 Group 1
allowances under § 97.621 and if the
Administrator makes the determination
under paragraph (c)(1) of this section
after making deductions for the source
that includes such recipient under
§ 97.624(b) for such control period, then
the Administrator will not make any
deduction to take account of such
already recorded TR SO2 Group 1
allowances.
(5)(i) With regard to the TR SO2 Group
1 allowances that are not recorded, or
that are deducted as an incorrect
allocation, in accordance with
paragraphs (c)(2) and (3) of this section
for a recipient under paragraph (c)(1)(i)
of this section, the Administrator will:
(A) Transfer such TR SO2 Group 1
allowances to the new unit set-aside for
such control period for the State from
whose SO2 Group 1 trading budget the
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48443
TR SO2 Group 1 allowances were
allocated; or
(B) If the State has a SIP revision
approved under § 52.39(e) or (f)
covering such control period, include
such TR SO2 Group 1 allowances in the
portion of the State SO2 Group 1 trading
budget that may be allocated for such
control period in accordance with such
SIP revision.
(ii) With regard to the TR SO2 Group
1 allowances that were not allocated
from the Indian country new unit setaside for such control period and that
are not recorded, or that are deducted as
an incorrect allocation, in accordance
with paragraphs (c)(2) and (3) of this
section for a recipient under paragraph
(c)(1)(ii) of this paragraph, the
Administrator will:
(A) Transfer such TR SO2 Group 1
allowances to the new unit set-aside for
such control period; or
(B) If the State has a SIP revision
approved under § 52.39(e) or (f)
covering such control period, include
such TR SO2 Group 1 allowances in the
portion of the State SO2 Group 1 trading
budget that may be allocated for such
control period in accordance with such
SIP revision.
(iii) With regard to the TR SO2 Group
1 allowances that were allocated from
the Indian country new unit set-aside
for such control period and that are not
recorded, or that are deducted as an
incorrect allocation, in accordance with
paragraphs (c)(2) and (3) of this section
for a recipient under paragraph (c)(1)(ii)
of this paragraph, the Administrator will
transfer such TR SO2 Group 1
allowances to the Indian country new
unit set-aside for such control period.
§ 97.612 TR SO2 Group 1 allowance
allocations to new units.
(a) For each control period in 2012
and thereafter and for the TR SO2 Group
1 units in each State, the Administrator
will allocate TR SO2 Group 1
allowances to the TR SO2 Group 1 units
as follows:
(1) The TR SO2 Group 1 allowances
will be allocated to the following TR
SO2 Group 1 units, except as provided
in paragraph (a)(10) of this section:
(i) TR SO2 Group 1 units that are not
allocated an amount of TR SO2 Group 1
allowances in the notice of data
availability issued under § 97.611(a)(1);
(ii) TR SO2 Group 1 units whose
allocation of an amount of TR SO2
Group 1 allowances for such control
period in the notice of data availability
issued under § 97.611(a)(1) is covered
by § 97.611(c)(2) or (3);
(iii) TR SO2 Group 1 units that are
allocated an amount of TR SO2 Group 1
allowances for such control period in
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the notice of data availability issued
under § 97.611(a)(1), which allocation is
terminated for such control period
pursuant to § 97.611(a)(2), and that
operate during the control period
immediately preceding such control
period; or
(iv) For purposes of paragraph (a)(9)
of this section, TR SO2 Group 1 units
under § 97.611(c)(1)(ii) whose allocation
of an amount of TR SO2 Group 1
allowances for such control period in
the notice of data availability issued
under § 97.611(b)(1)(ii)(B) is covered by
§ 97.611(c)(2) or (3).
(2) The Administrator will establish a
separate new unit set-aside for the State
for each such control period. Each such
new unit set-aside will be allocated TR
SO2 Group 1 allowances in an amount
equal to the applicable amount of tons
of SO2 emissions as set forth in
§ 97.610(a) and will be allocated
additional TR SO2 Group 1 allowances
(if any) in accordance with
§§ 97.611(a)(2) and (c)(5) and paragraph
(b)(10) of this section.
(3) The Administrator will determine,
for each TR SO2 Group 1 unit described
in paragraph (a)(1) of this section, an
allocation of TR SO2 Group 1
allowances for the later of the following
control periods and for each subsequent
control period:
(i) The control period in 2012;
(ii) The first control period after the
control period in which the TR SO2
Group 1 unit commences commercial
operation;
(iii) For a unit described in paragraph
(a)(1)(ii) of this section, the first control
period in which the TR SO2 Group 1
unit operates in the State after operating
in another jurisdiction and for which
the unit is not already allocated one or
more TR SO2 Group 1 allowances; and
(iv) For a unit described in paragraph
(a)(1)(iii) of this section, the first control
period after the control period in which
the unit resumes operation.
(4)(i) The allocation to each TR SO2
annual unit described in paragraph
(a)(1)(i) through (iii) of this section and
for each control period described in
paragraph (a)(3) of this section will be
an amount equal to the unit’s total tons
of SO2 emissions during the
immediately preceding control period.
(ii) The Administrator will adjust the
allocation amount in paragraph (a)(4)(i)
in accordance with paragraphs (a)(5)
through (7) and (12) of this section.
(5) The Administrator will calculate
the sum of the TR SO2 Group 1
allowances determined for all such TR
SO2 Group 1 units under paragraph
(a)(4)(i) of this section in the State for
such control period.
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(6) If the amount of TR SO2 Group 1
allowances in the new unit set-aside for
the State for such control period is
greater than or equal to the sum under
paragraph (a)(5) of this section, then the
Administrator will allocate the amount
of TR SO2 Group 1 allowances
determined for each such TR SO2 Group
1 unit under paragraph (a)(4)(i) of this
section.
(7) If the amount of TR SO2 Group 1
allowances in the new unit set-aside for
the State for such control period is less
than the sum under paragraph (a)(5) of
this section, then the Administrator will
allocate to each such TR SO2 Group 1
unit the amount of the TR SO2 Group 1
allowances determined under paragraph
(a)(4)(i) of this section for the unit,
multiplied by the amount of TR SO2
Group 1 allowances in the new unit setaside for such control period, divided
by the sum under paragraph (a)(5) of
this section, and rounded to the nearest
allowance.
(8) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.611(b)(1)(i) and (ii), of the amount
of TR SO2 Group 1 allowances allocated
under paragraphs (a)(2) through (7) and
(12) of this section for such control
period to each TR SO2 Group 1 unit
eligible for such allocation.
(9) If, after completion of the
procedures under paragraphs (a)(5)
through (8) of this section for such
control period, any unallocated TR SO2
Group 1 allowances remain in the new
unit set-aside for the State for such
control period, the Administrator will
allocate such TR SO2 Group 1
allowances as follows—
(i) The Administrator will determine,
for each unit described in paragraph
(a)(1) of this section that commenced
commercial operation during the period
starting January 1 of the year before the
year of such control period and ending
November 30 of year of such control
period, the positive difference (if any)
between the unit’s emissions during
such control period and the amount of
TR SO2 Group 1 allowances referenced
in the notice of data availability
required under § 97.611(b)(1)(ii) for the
unit for such control period;
(ii) The Administrator will determine
the sum of the positive differences
determined under paragraph (a)(9)(i) of
this section;
(iii) If the amount of unallocated TR
SO2 Group 1 allowances remaining in
the new unit set-aside for the State for
such control period is greater than or
equal to the sum determined under
paragraph (a)(9)(ii) of this section, then
the Administrator will allocate the
amount of TR SO2 Group 1 allowances
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determined for each such TR SO2 Group
1 unit under paragraph (a)(9)(i) of this
section; and
(iv) If the amount of unallocated TR
SO2 Group 1 allowances remaining in
the new unit set-aside for the State for
such control period is less than the sum
under paragraph (a)(9)(ii) of this section,
then the Administrator will allocate to
each such TR SO2 Group 1 unit the
amount of the TR SO2 Group 1
allowances determined under paragraph
(a)(9)(i) of this section for the unit,
multiplied by the amount of unallocated
TR SO2 Group 1 allowances remaining
in the new unit set-aside for such
control period, divided by the sum
under paragraph (a)(9)(ii) of this section,
and rounded to the nearest allowance.
(10) If, after completion of the
procedures under paragraphs (a)(9) and
(12) of this section for such control
period, any unallocated TR SO2 Group
1 allowances remain in the new unit setaside for the State for such control
period, the Administrator will allocate
to each TR SO2 Group 1 unit that is in
the State, is allocated an amount of TR
SO2 Group 1 allowances in the notice of
data availability issued under
§ 97.611(a)(1), and continues to be
allocated TR SO2 Group 1 allowances
for such control period in accordance
with § 97.611(a)(2), an amount of TR
SO2 Group 1 allowances equal to the
following: The total amount of such
remaining unallocated TR SO2 Group 1
allowances in such new unit set-aside,
multiplied by the unit’s allocation
under § 97.611(a) for such control
period, divided by the remainder of the
amount of tons in the applicable State
SO2 Group 1 trading budget minus the
sum of the amounts of tons in such new
unit set-aside and the Indian country
new unit set-aside for the State for such
control period, and rounded to the
nearest allowance.
(11) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.611(b)(1)(iii), (iv), and (v), of the
amount of TR SO2 Group 1 allowances
allocated under paragraphs (a)(9), (10),
and (12) of this section for such control
period to each TR SO2 Group 1 unit
eligible for such allocation.
(12)(i) Notwithstanding the
requirements of paragraphs (a)(2)
through (11) of this section, if the
calculations of allocations of a new unit
set-aside for a control period in a given
year under paragraph (a)(7) of this
section, paragraphs (a)(6) and (9)(iv) of
this section, or paragraphs (a)(6), (9)(iii),
and (10) of this section would otherwise
result in total allocations of such new
unit set-aside exceeding the total
amount of such new unit set-aside, then
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the Administrator will adjust the results
of the calculations under paragraph
(a)(7), (9)(iv), or (10) of this section, as
applicable, as follows. The
Administrator will list the TR SO2
Group 1 units in descending order based
on the amount of such units’ allocations
under paragraph (a)(7), (9)(iv), or (10) of
this section, as applicable, and, in cases
of equal allocation amounts, in
alphabetical order of the relevant
source’s name and numerical order of
the relevant unit’s identification
number, and will reduce each unit’s
allocation under paragraph (a)(7),
(9)(iv), or (10) of this section, as
applicable, by one TR SO2 Group 1
allowance (but not below zero) in the
order in which the units are listed and
will repeat this reduction process as
necessary, until the total allocations of
such new unit set-aside equal the total
amount of such new unit set-aside.
(ii) Notwithstanding the requirements
of paragraphs (a)(10) and (11) of this
section, if the calculations of allocations
of a new unit set-aside for a control
period in a given year under paragraphs
(a)(6), (9)(iii), and (10) of this section
would otherwise result in a total
allocations of such new unit set-aside
less than the total amount of such new
unit set-aside, then the Administrator
will adjust the results of the calculations
under paragraph (a)(10) of this section,
as follows. The Administrator will list
the TR SO2 Group 1 units in descending
order based on the amount of such
units’ allocations under paragraph
(a)(10) of this section and, in cases of
equal allocation amounts, in
alphabetical order of the relevant
source’s name and numerical order of
the relevant unit’s identification
number, and will increase each unit’s
allocation under paragraph (a)(10) of
this section by one TR SO2 Group 1
allowance in the order in which the
units are listed and will repeat this
increase process as necessary, until the
total allocations of such new unit setaside equal the total amount of such
new unit set-aside.
(b) For each control period in 2012
and thereafter and for the TR SO2 Group
1 units located in Indian country within
the borders of each State, the
Administrator will allocate TR SO2
Group 1 allowances to the TR SO2
Group 1 units as follows:
(1) The TR SO2 Group 1 allowances
will be allocated to the following TR
SO2 Group 1 units, except as provided
in paragraph (b)(10) of this section:
(i) TR SO2 Group 1 units that are not
allocated an amount of TR SO2 Group 1
allowances in the notice of data
availability issued under § 97.611(a)(1);
or
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(ii) For purposes of paragraph (b)(9) of
this section, TR SO2 Group 1 units
under § 97.611(c)(1)(ii) whose allocation
of an amount of TR SO2 Group 1
allowances for such control period in
the notice of data availability issued
under § 97.611(b)(2)(ii)(B) is covered by
§ 97.611(c)(2) or (3).
(2) The Administrator will establish a
separate Indian country new unit setaside for the State for each such control
period. Each such Indian country new
unit set-aside will be allocated TR SO2
Group 1 allowances in an amount equal
to the applicable amount of tons of SO2
emissions as set forth in § 97.610(a) and
will be allocated additional TR SO2
Group 1 allowances (if any) in
accordance with § 97.611(c)(5).
(3) The Administrator will determine,
for each TR SO2 Group 1 unit described
in paragraph (b)(1) of this section, an
allocation of TR SO2 Group 1
allowances for the later of the following
control periods and for each subsequent
control period:
(i) The control period in 2012; and
(ii) The first control period after the
control period in which the TR SO2
Group 1 unit commences commercial
operation.
(4)(i) The allocation to each TR SO2
annual unit described in paragraph
(b)(1)(i) of this section and for each
control period described in paragraph
(b)(3) of this section will be an amount
equal to the unit’s total tons of SO2
emissions during the immediately
preceding control period.
(ii) The Administrator will adjust the
allocation amount in paragraph (b)(4)(i)
in accordance with paragraphs (b)(5)
through (7) and (12) of this section.
(5) The Administrator will calculate
the sum of the TR SO2 Group 1
allowances determined for all such TR
SO2 Group 1 units under paragraph
(b)(4)(i) of this section in Indian country
within the borders of the State for such
control period.
(6) If the amount of TR SO2 Group 1
allowances in the Indian country new
unit set-aside for the State for such
control period is greater than or equal to
the sum under paragraph (b)(5) of this
section, then the Administrator will
allocate the amount of TR SO2 Group 1
allowances determined for each such TR
SO2 Group 1 unit under paragraph
(b)(4)(i) of this section.
(7) If the amount of TR SO2 Group 1
allowances in the Indian country new
unit set-aside for the State for such
control period is less than the sum
under paragraph (b)(5) of this section,
then the Administrator will allocate to
each such TR SO2 Group 1 unit the
amount of the TR SO2 Group 1
allowances determined under paragraph
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48445
(b)(4)(i) of this section for the unit,
multiplied by the amount of TR SO2
Group 1 allowances in the Indian
country new unit set-aside for such
control period, divided by the sum
under paragraph (b)(5) of this section,
and rounded to the nearest allowance.
(8) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.611(b)(2)(i) and (ii), of the amount
of TR SO2 Group 1 allowances allocated
under paragraphs (b)(2) through (7) and
(12) of this section for such control
period to each TR SO2 Group 1 unit
eligible for such allocation.
(9) If, after completion of the
procedures under paragraphs (b)(5)
through (8) of this section for such
control period, any unallocated TR SO2
Group 1 allowances remain in the
Indian country new unit set-aside for
the State for such control period, the
Administrator will allocate such TR SO2
Group 1 allowances as follows—
(i) The Administrator will determine,
for each unit described in paragraph
(b)(1) of this section that commenced
commercial operation during the period
starting January 1 of the year before the
year of such control period and ending
November 30 of year of such control
period, the positive difference (if any)
between the unit’s emissions during
such control period and the amount of
TR SO2 Group 1 allowances referenced
in the notice of data availability
required under § 97.611(b)(2)(ii) for the
unit for such control period;
(ii) The Administrator will determine
the sum of the positive differences
determined under paragraph (b)(9)(i) of
this section;
(iii) If the amount of unallocated TR
SO2 Group 1 allowances remaining in
the Indian country new unit set-aside
for the State for such control period is
greater than or equal to the sum
determined under paragraph (b)(9)(ii) of
this section, then the Administrator will
allocate the amount of TR SO2 Group 1
allowances determined for each such TR
SO2 Group 1 unit under paragraph
(b)(9)(i) of this section; and
(iv) If the amount of unallocated TR
SO2 Group 1 allowances remaining in
the Indian country new unit set-aside
for the State for such control period is
less than the sum under paragraph
(b)(9)(ii) of this section, then the
Administrator will allocate to each such
TR SO2 Group 1 unit the amount of the
TR SO2 Group 1 allowances determined
under paragraph (b)(9)(i) of this section
for the unit, multiplied by the amount
of unallocated TR SO2 Group 1
allowances remaining in the Indian
country new unit set-aside for such
control period, divided by the sum
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under paragraph (b)(9)(ii) of this section,
and rounded to the nearest allowance.
(10) If, after completion of the
procedures under paragraphs (b)(9) and
(12) of this section for such control
period, any unallocated TR SO2 Group
1 allowances remain in the Indian
country new unit set-aside for the State
for such control period, the
Administrator will:
(i) Transfer such unallocated TR SO2
Group 1 allowances to the new unit setaside for the State for such control
period; or
(ii) If the State has a SIP revision
approved under § 52.39(d), (e), or (f) of
this chapter covering such control
period, include such unallocated TR
SO2 Group 1 allowances in the portion
of the State SO2 Group 1 trading budget
that may be allocated for such control
period in accordance with such SIP
revision.
(11) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.611(b)(2)(iii), (iv), and (v), of the
amount of TR SO2 Group 1 allowances
allocated under paragraphs (b)(9), (10),
and (12) for such control period to each
TR SO2 Group 1 unit eligible for such
allocation.
(12)(i) Notwithstanding the
requirements of paragraphs (b)(2)
through (11) of this section, if the
calculations of allocations of an Indian
country new unit set-aside for a control
period in a given year under paragraph
(b)(7) of this section, paragraphs (b)(6)
and (9)(iv) of this section, or paragraphs
(b)(6), (9)(iii), and (10) of this section
would otherwise result in total
allocations of such Indian country new
unit set-aside exceeding the total
amount of such Indian country new unit
set-aside, then the Administrator will
adjust the results of the calculations
under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, as follows.
The Administrator will list the TR SO2
Group 1 units in descending order based
on the amount of such units’ allocations
under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, and, in cases
of equal allocation amounts, in
alphabetical order of the relevant
source’s name and numerical order of
the relevant unit’s identification
number, and will reduce each unit’s
allocation under paragraph (b)(7),
(9)(iv), or (10) of this section, as
applicable, by one TR SO2 Group 1
allowance (but not below zero) in the
order in which the units are listed and
will repeat this reduction process as
necessary, until the total allocations of
such Indian country new unit set-aside
equal the total amount of such Indian
country new unit set-aside.
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(ii) Notwithstanding the requirements
of paragraphs (b)(10) and (11) of this
section, if the calculations of allocations
of an Indian country new unit set-aside
for a control period in a given year
under paragraphs (b)(6), (9)(iii), and (10)
of this section would otherwise result in
a total allocations of such Indian
country new unit set-aside less than the
total amount of such Indian country
new unit set-aside, then the
Administrator will adjust the results of
the calculations under paragraph (b)(10)
of this section, as follows. The
Administrator will list the TR SO2
Group 1 units in descending order based
on the amount of such units’ allocations
under paragraph (b)(10) of this section
and, in cases of equal allocation
amounts, in alphabetical order of the
relevant source’s name and numerical
order of the relevant unit’s
identification number, and will increase
each unit’s allocation under paragraph
(b)(10) of this section by one TR SO2
Group 1 allowance in the order in
which the units are listed and will
repeat this increase process as
necessary, until the total allocations of
such Indian country new unit set-aside
equal the total amount of such Indian
country new unit set-aside.
§ 97.613 Authorization of designated
representative and alternate designated
representative.
(a) Except as provided under § 97.615,
each TR SO2 Group 1 source, including
all TR SO2 Group 1 units at the source,
shall have one and only one designated
representative, with regard to all matters
under the TR SO2 Group 1 Trading
Program.
(1) The designated representative
shall be selected by an agreement
binding on the owners and operators of
the source and all TR SO2 Group 1 units
at the source and shall act in accordance
with the certification statement in
§ 97.616(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 97.616:
(i) The designated representative shall
be authorized and shall represent and,
by his or her representations, actions,
inactions, or submissions, legally bind
each owner and operator of the source
and each TR SO2 Group 1 unit at the
source in all matters pertaining to the
TR SO2 Group 1 Trading Program,
notwithstanding any agreement between
the designated representative and such
owners and operators; and
(ii) The owners and operators of the
source and each TR SO2 Group 1 unit
at the source shall be bound by any
decision or order issued to the
designated representative by the
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Administrator regarding the source or
any such unit.
(b) Except as provided under § 97.615,
each TR SO2 Group 1 source may have
one and only one alternate designated
representative, who may act on behalf of
the designated representative. The
agreement by which the alternate
designated representative is selected
shall include a procedure for
authorizing the alternate designated
representative to act in lieu of the
designated representative.
(1) The alternate designated
representative shall be selected by an
agreement binding on the owners and
operators of the source and all TR SO2
Group 1 units at the source and shall act
in accordance with the certification
statement in § 97.616(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 97.616,
(i) The alternate designated
representative shall be authorized;
(ii) Any representation, action,
inaction, or submission by the alternate
designated representative shall be
deemed to be a representation, action,
inaction, or submission by the
designated representative; and
(iii) The owners and operators of the
source and each TR SO2 Group 1 unit
at the source shall be bound by any
decision or order issued to the alternate
designated representative by the
Administrator regarding the source or
any such unit.
(c) Except in this section, § 97.602,
and §§ 97.614 through 97.618, whenever
the term ‘‘designated representative’’ (as
distinguished from the term ‘‘common
designated representative’’) is used in
this subpart, the term shall be construed
to include the designated representative
or any alternate designated
representative.
§ 97.614 Responsibilities of designated
representative and alternate designated
representative.
(a) Except as provided under § 97.618
concerning delegation of authority to
make submissions, each submission
under the TR SO2 Group 1 Trading
Program shall be made, signed, and
certified by the designated
representative or alternate designated
representative for each TR SO2 Group 1
source and TR SO2 Group 1 unit for
which the submission is made. Each
such submission shall include the
following certification statement by the
designated representative or alternate
designated representative: ‘‘I am
authorized to make this submission on
behalf of the owners and operators of
the source or units for which the
submission is made. I certify under
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penalty of law that I have personally
examined, and am familiar with, the
statements and information submitted
in this document and all its
attachments. Based on my inquiry of
those individuals with primary
responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(b) The Administrator will accept or
act on a submission made for a TR SO2
Group 1 source or a TR SO2 Group 1
unit only if the submission has been
made, signed, and certified in
accordance with paragraph (a) of this
section and § 97.618.
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§ 97.615 Changing designated
representative and alternate designated
representative; changes in owners and
operators; changes in units at the source.
(a) Changing designated
representative. The designated
representative may be changed at any
time upon receipt by the Administrator
of a superseding complete certificate of
representation under § 97.616.
Notwithstanding any such change, all
representations, actions, inactions, and
submissions by the previous designated
representative before the time and date
when the Administrator receives the
superseding certificate of representation
shall be binding on the new designated
representative and the owners and
operators of the TR SO2 Group 1 source
and the TR SO2 Group 1 units at the
source.
(b) Changing alternate designated
representative. The alternate designated
representative may be changed at any
time upon receipt by the Administrator
of a superseding complete certificate of
representation under § 97.616.
Notwithstanding any such change, all
representations, actions, inactions, and
submissions by the previous alternate
designated representative before the
time and date when the Administrator
receives the superseding certificate of
representation shall be binding on the
new alternate designated representative,
the designated representative, and the
owners and operators of the TR SO2
Group 1 source and the TR SO2 Group
1 units at the source.
(c) Changes in owners and operators.
(1) In the event an owner or operator of
a TR SO2 Group 1 source or a TR SO2
Group 1 unit at the source is not
included in the list of owners and
operators in the certificate of
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representation under § 97.616, such
owner or operator shall be deemed to be
subject to and bound by the certificate
of representation, the representations,
actions, inactions, and submissions of
the designated representative and any
alternate designated representative of
the source or unit, and the decisions
and orders of the Administrator, as if
the owner or operator were included in
such list.
(2) Within 30 days after any change in
the owners and operators of a TR SO2
Group 1 source or a TR SO2 Group 1
unit at the source, including the
addition or removal of an owner or
operator, the designated representative
or any alternate designated
representative shall submit a revision to
the certificate of representation under
§ 97.616 amending the list of owners
and operators to reflect the change.
(d) Changes in units at the source.
Within 30 days of any change in which
units are located at a TR SO2 Group 1
source (including the addition or
removal of a unit), the designated
representative or any alternate
designated representative shall submit a
certificate of representation under
§ 97.616 amending the list of units to
reflect the change.
(1) If the change is the addition of a
unit that operated (other than for
purposes of testing by the manufacturer
before initial installation) before being
located at the source, then the certificate
of representation shall identify, in a
format prescribed by the Administrator,
the entity from whom the unit was
purchased or otherwise obtained
(including name, address, telephone
number, and facsimile number (if any)),
the date on which the unit was
purchased or otherwise obtained, and
the date on which the unit became
located at the source.
(2) If the change is the removal of a
unit, then the certificate of
representation shall identify, in a format
prescribed by the Administrator, the
entity to which the unit was sold or that
otherwise obtained the unit (including
name, address, telephone number, and
facsimile number (if any)), the date on
which the unit was sold or otherwise
obtained, and the date on which the
unit became no longer located at the
source.
§ 97.616
Certificate of representation.
(a) A complete certificate of
representation for a designated
representative or an alternate designated
representative shall include the
following elements in a format
prescribed by the Administrator:
(1) Identification of the TR SO2 Group
1 source, and each TR SO2 Group 1 unit
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48447
at the source, for which the certificate
of representation is submitted,
including source name, source category
and NAICS code (or, in the absence of
a NAICS code, an equivalent code),
State, plant code, county, latitude and
longitude, unit identification number
and type, identification number and
nameplate capacity (in MWe, rounded
to the nearest tenth) of each generator
served by each such unit, actual or
projected date of commencement of
commercial operation, and a statement
of whether such source is located in
Indian Country. If a projected date of
commencement of commercial
operation is provided, the actual date of
commencement of commercial
operation shall be provided when such
information becomes available.
(2) The name, address, e-mail address
(if any), telephone number, and
facsimile transmission number (if any)
of the designated representative and any
alternate designated representative.
(3) A list of the owners and operators
of the TR SO2 Group 1 source and of
each TR SO2 Group 1 unit at the source.
(4) The following certification
statements by the designated
representative and any alternate
designated representative—
(i) ‘‘I certify that I was selected as the
designated representative or alternate
designated representative, as applicable,
by an agreement binding on the owners
and operators of the source and each TR
SO2 Group 1 unit at the source.’’
(ii) ‘‘I certify that I have all the
necessary authority to carry out my
duties and responsibilities under the TR
SO2 Group 1 Trading Program on behalf
of the owners and operators of the
source and of each TR SO2 Group 1 unit
at the source and that each such owner
and operator shall be fully bound by my
representations, actions, inactions, or
submissions and by any decision or
order issued to me by the Administrator
regarding the source or unit.’’
(iii) ‘‘Where there are multiple
holders of a legal or equitable title to, or
a leasehold interest in, a TR SO2 Group
1 unit, or where a utility or industrial
customer purchases power from a TR
SO2 Group 1 unit under a life-of-theunit, firm power contractual
arrangement, I certify that: I have given
a written notice of my selection as the
‘designated representative’ or ‘alternate
designated representative’, as
applicable, and of the agreement by
which I was selected to each owner and
operator of the source and of each TR
SO2 Group 1 unit at the source; and TR
SO2 Group 1 allowances and proceeds
of transactions involving TR SO2 Group
1 allowances will be deemed to be held
or distributed in proportion to each
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holder’s legal, equitable, leasehold, or
contractual reservation or entitlement,
except that, if such multiple holders
have expressly provided for a different
distribution of TR SO2 Group 1
allowances by contract, TR SO2 Group
1 allowances and proceeds of
transactions involving TR SO2 Group 1
allowances will be deemed to be held or
distributed in accordance with the
contract.’’
(5) The signature of the designated
representative and any alternate
designated representative and the dates
signed.
(b) Unless otherwise required by the
Administrator, documents of agreement
referred to in the certificate of
representation shall not be submitted to
the Administrator. The Administrator
shall not be under any obligation to
review or evaluate the sufficiency of
such documents, if submitted.
§ 97.617 Objections concerning
designated representative and alternate
designated representative.
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(a) Once a complete certificate of
representation under § 97.616 has been
submitted and received, the
Administrator will rely on the certificate
of representation unless and until a
superseding complete certificate of
representation under § 97.616 is
received by the Administrator.
(b) Except as provided in paragraph
(a) of this section, no objection or other
communication submitted to the
Administrator concerning the
authorization, or any representation,
action, inaction, or submission, of a
designated representative or alternate
designated representative shall affect
any representation, action, inaction, or
submission of the designated
representative or alternate designated
representative or the finality of any
decision or order by the Administrator
under the TR SO2 Group 1 Trading
Program.
(c) The Administrator will not
adjudicate any private legal dispute
concerning the authorization or any
representation, action, inaction, or
submission of any designated
representative or alternate designated
representative, including private legal
disputes concerning the proceeds of TR
SO2 Group 1 allowance transfers.
§ 97.618 Delegation by designated
representative and alternate designated
representative.
(a) A designated representative may
delegate, to one or more natural persons,
his or her authority to make an
electronic submission to the
Administrator provided for or required
under this subpart.
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(b) An alternate designated
representative may delegate, to one or
more natural persons, his or her
authority to make an electronic
submission to the Administrator
provided for or required under this
subpart.
(c) In order to delegate authority to a
natural person to make an electronic
submission to the Administrator in
accordance with paragraph (a) or (b) of
this section, the designated
representative or alternate designated
representative, as appropriate, must
submit to the Administrator a notice of
delegation, in a format prescribed by the
Administrator, that includes the
following elements:
(1) The name, address, e-mail address,
telephone number, and facsimile
transmission number (if any) of such
designated representative or alternate
designated representative;
(2) The name, address, e-mail address,
telephone number, and facsimile
transmission number (if any) of each
such natural person (referred to in this
section as an ‘‘agent’’);
(3) For each such natural person, a list
of the type or types of electronic
submissions under paragraph (a) or (b)
of this section for which authority is
delegated to him or her; and
(4) The following certification
statements by such designated
representative or alternate designated
representative:
(i) ‘‘I agree that any electronic
submission to the Administrator that is
made by an agent identified in this
notice of delegation and of a type listed
for such agent in this notice of
delegation and that is made when I am
a designated representative or alternate
designated representative, as
appropriate, and before this notice of
delegation is superseded by another
notice of delegation under 40 CFR
97.618(d) shall be deemed to be an
electronic submission by me.’’
(ii) ‘‘Until this notice of delegation is
superseded by another notice of
delegation under 40 CFR 97.618(d), I
agree to maintain an e-mail account and
to notify the Administrator immediately
of any change in my e-mail address
unless all delegation of authority by me
under 40 CFR 97.618 is terminated.’’.
(d) A notice of delegation submitted
under paragraph (c) of this section shall
be effective, with regard to the
designated representative or alternate
designated representative identified in
such notice, upon receipt of such notice
by the Administrator and until receipt
by the Administrator of a superseding
notice of delegation submitted by such
designated representative or alternate
designated representative, as
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appropriate. The superseding notice of
delegation may replace any previously
identified agent, add a new agent, or
eliminate entirely any delegation of
authority.
(e) Any electronic submission covered
by the certification in paragraph (c)(4)(i)
of this section and made in accordance
with a notice of delegation effective
under paragraph (d) of this section shall
be deemed to be an electronic
submission by the designated
representative or alternate designated
representative submitting such notice of
delegation.
§ 97.619
[Reserved]
§ 97.620 Establishment of compliance
accounts, assurance accounts, and general
accounts.
(a) Compliance accounts. Upon
receipt of a complete certificate of
representation under § 97.616, the
Administrator will establish a
compliance account for the TR SO2
Group 1 source for which the certificate
of representation was submitted, unless
the source already has a compliance
account. The designated representative
and any alternate designated
representative of the source shall be the
authorized account representative and
the alternate authorized account
representative respectively of the
compliance account.
(b) Assurance accounts. The
Administrator will establish assurance
accounts for certain owners and
operators and States in accordance with
§ 97.625(b)(3).
(c) General accounts. (1) Application
for general account. (i) Any person may
apply to open a general account, for the
purpose of holding and transferring TR
SO2 Group 1 allowances, by submitting
to the Administrator a complete
application for a general account. Such
application shall designate one and only
one authorized account representative
and may designate one and only one
alternate authorized account
representative who may act on behalf of
the authorized account representative.
(A) The authorized account
representative and alternate authorized
account representative shall be selected
by an agreement binding on the persons
who have an ownership interest with
respect to TR SO2 Group 1 allowances
held in the general account.
(B) The agreement by which the
alternate authorized account
representative is selected shall include
a procedure for authorizing the alternate
authorized account representative to act
in lieu of the authorized account
representative.
(ii) A complete application for a
general account shall include the
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following elements in a format
prescribed by the Administrator:
(A) Name, mailing address, e-mail
address (if any), telephone number, and
facsimile transmission number (if any)
of the authorized account representative
and any alternate authorized account
representative;
(B) An identifying name for the
general account;
(C) A list of all persons subject to a
binding agreement for the authorized
account representative and any alternate
authorized account representative to
represent their ownership interest with
respect to the TR SO2 Group 1
allowances held in the general account;
(D) The following certification
statement by the authorized account
representative and any alternate
authorized account representative: ‘‘I
certify that I was selected as the
authorized account representative or the
alternate authorized account
representative, as applicable, by an
agreement that is binding on all persons
who have an ownership interest with
respect to TR SO2 Group 1 allowances
held in the general account. I certify that
I have all the necessary authority to
carry out my duties and responsibilities
under the TR SO2 Group 1 Trading
Program on behalf of such persons and
that each such person shall be fully
bound by my representations, actions,
inactions, or submissions and by any
decision or order issued to me by the
Administrator regarding the general
account.’’
(E) The signature of the authorized
account representative and any alternate
authorized account representative and
the dates signed.
(iii) Unless otherwise required by the
Administrator, documents of agreement
referred to in the application for a
general account shall not be submitted
to the Administrator. The Administrator
shall not be under any obligation to
review or evaluate the sufficiency of
such documents, if submitted.
(2) Authorization of authorized
account representative and alternate
authorized account representative. (i)
Upon receipt by the Administrator of a
complete application for a general
account under paragraph (b)(1) of this
section, the Administrator will establish
a general account for the person or
persons for whom the application is
submitted, and upon and after such
receipt by the Administrator:
(A) The authorized account
representative of the general account
shall be authorized and shall represent
and, by his or her representations,
actions, inactions, or submissions,
legally bind each person who has an
ownership interest with respect to TR
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SO2 Group 1 allowances held in the
general account in all matters pertaining
to the TR SO2 Group 1 Trading Program,
notwithstanding any agreement between
the authorized account representative
and such person.
(B) Any alternate authorized account
representative shall be authorized, and
any representation, action, inaction, or
submission by any alternate authorized
account representative shall be deemed
to be a representation, action, inaction,
or submission by the authorized account
representative.
(C) Each person who has an
ownership interest with respect to TR
SO2 Group 1 allowances held in the
general account shall be bound by any
decision or order issued to the
authorized account representative or
alternate authorized account
representative by the Administrator
regarding the general account.
(ii) Except as provided in paragraph
(c)(5) of this section concerning
delegation of authority to make
submissions, each submission
concerning the general account shall be
made, signed, and certified by the
authorized account representative or
any alternate authorized account
representative for the persons having an
ownership interest with respect to TR
SO2 Group 1 allowances held in the
general account. Each such submission
shall include the following certification
statement by the authorized account
representative or any alternate
authorized account representative: ‘‘I
am authorized to make this submission
on behalf of the persons having an
ownership interest with respect to the
TR SO2 Group 1 allowances held in the
general account. I certify under penalty
of law that I have personally examined,
and am familiar with, the statements
and information submitted in this
document and all its attachments. Based
on my inquiry of those individuals with
primary responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(iii) Except in this section, whenever
the term ‘‘authorized account
representative’’ is used in this subpart,
the term shall be construed to include
the authorized account representative or
any alternate authorized account
representative.
(3) Changing authorized account
representative and alternate authorized
account representative; changes in
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48449
persons with ownership interest. (i) The
authorized account representative of a
general account may be changed at any
time upon receipt by the Administrator
of a superseding complete application
for a general account under paragraph
(c)(1) of this section. Notwithstanding
any such change, all representations,
actions, inactions, and submissions by
the previous authorized account
representative before the time and date
when the Administrator receives the
superseding application for a general
account shall be binding on the new
authorized account representative and
the persons with an ownership interest
with respect to the TR SO2 Group 1
allowances in the general account.
(ii) The alternate authorized account
representative of a general account may
be changed at any time upon receipt by
the Administrator of a superseding
complete application for a general
account under paragraph (c)(1) of this
section. Notwithstanding any such
change, all representations, actions,
inactions, and submissions by the
previous alternate authorized account
representative before the time and date
when the Administrator receives the
superseding application for a general
account shall be binding on the new
alternate authorized account
representative, the authorized account
representative, and the persons with an
ownership interest with respect to the
TR SO2 Group 1 allowances in the
general account.
(iii)(A) In the event a person having
an ownership interest with respect to
TR SO2 Group 1 allowances in the
general account is not included in the
list of such persons in the application
for a general account, such person shall
be deemed to be subject to and bound
by the application for a general account,
the representation, actions, inactions,
and submissions of the authorized
account representative and any alternate
authorized account representative of the
account, and the decisions and orders of
the Administrator, as if the person were
included in such list.
(B) Within 30 days after any change
in the persons having an ownership
interest with respect to SO2 Group 1
allowances in the general account,
including the addition or removal of a
person, the authorized account
representative or any alternate
authorized account representative shall
submit a revision to the application for
a general account amending the list of
persons having an ownership interest
with respect to the TR SO2 Group 1
allowances in the general account to
include the change.
(4) Objections concerning authorized
account representative and alternate
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authorized account representative. (i)
Once a complete application for a
general account under paragraph (c)(1)
of this section has been submitted and
received, the Administrator will rely on
the application unless and until a
superseding complete application for a
general account under paragraph (b)(1)
of this section is received by the
Administrator.
(ii) Except as provided in paragraph
(c)(4)(i) of this section, no objection or
other communication submitted to the
Administrator concerning the
authorization, or any representation,
action, inaction, or submission of the
authorized account representative or
any alternate authorized account
representative of a general account shall
affect any representation, action,
inaction, or submission of the
authorized account representative or
any alternate authorized account
representative or the finality of any
decision or order by the Administrator
under the TR SO2 Group 1 Trading
Program.
(iii) The Administrator will not
adjudicate any private legal dispute
concerning the authorization or any
representation, action, inaction, or
submission of the authorized account
representative or any alternate
authorized account representative of a
general account, including private legal
disputes concerning the proceeds of TR
SO2 Group 1 allowance transfers.
(5) Delegation by authorized account
representative and alternate authorized
account representative. (i) An
authorized account representative of a
general account may delegate, to one or
more natural persons, his or her
authority to make an electronic
submission to the Administrator
provided for or required under this
subpart.
(ii) An alternate authorized account
representative of a general account may
delegate, to one or more natural persons,
his or her authority to make an
electronic submission to the
Administrator provided for or required
under this subpart.
(iii) In order to delegate authority to
a natural person to make an electronic
submission to the Administrator in
accordance with paragraph (c)(5)(i) or
(ii) of this section, the authorized
account representative or alternate
authorized account representative, as
appropriate, must submit to the
Administrator a notice of delegation, in
a format prescribed by the
Administrator, that includes the
following elements:
(A) The name, address, e-mail
address, telephone number, and
facsimile transmission number (if any)
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of such authorized account
representative or alternate authorized
account representative;
(B) The name, address, e-mail
address, telephone number, and
facsimile transmission number (if any)
of each such natural person (referred to
in this section as an ‘‘agent’’);
(C) For each such natural person, a
list of the type or types of electronic
submissions under paragraph (c)(5)(i) or
(ii) of this section for which authority is
delegated to him or her;
(D) The following certification
statement by such authorized account
representative or alternate authorized
account representative: ‘‘I agree that any
electronic submission to the
Administrator that is made by an agent
identified in this notice of delegation
and of a type listed for such agent in
this notice of delegation and that is
made when I am an authorized account
representative or alternate authorized
representative, as appropriate, and
before this notice of delegation is
superseded by another notice of
delegation under 40 CFR 97.620(c)(5)(iv)
shall be deemed to be an electronic
submission by me.’’; and
(E) The following certification
statement by such authorized account
representative or alternate authorized
account representative: ‘‘Until this
notice of delegation is superseded by
another notice of delegation under 40
CFR 97.620(c)(5)(iv), I agree to maintain
an e-mail account and to notify the
Administrator immediately of any
change in my e-mail address unless all
delegation of authority by me under 40
CFR 97.620(c)(5) is terminated.’’.
(iv) A notice of delegation submitted
under paragraph (c)(5)(iii) of this section
shall be effective, with regard to the
authorized account representative or
alternate authorized account
representative identified in such notice,
upon receipt of such notice by the
Administrator and until receipt by the
Administrator of a superseding notice of
delegation submitted by such
authorized account representative or
alternate authorized account
representative, as appropriate. The
superseding notice of delegation may
replace any previously identified agent,
add a new agent, or eliminate entirely
any delegation of authority.
(v) Any electronic submission covered
by the certification in paragraph
(c)(5)(iii)(D) of this section and made in
accordance with a notice of delegation
effective under paragraph (c)(5)(iv) of
this section shall be deemed to be an
electronic submission by the designated
representative or alternate designated
representative submitting such notice of
delegation.
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(6) Closing a general account. (i) The
authorized account representative or
alternate authorized account
representative of a general account may
submit to the Administrator a request to
close the account. Such request shall
include a correctly submitted TR SO2
Group 1 allowance transfer under
§ 97.622 for any TR SO2 Group 1
allowances in the account to one or
more other Allowance Management
System accounts.
(ii) If a general account has no TR SO2
Group 1 allowance transfers to or from
the account for a 12-month period or
longer and does not contain any TR SO2
Group 1 allowances, the Administrator
may notify the authorized account
representative for the account that the
account will be closed after 30 days
after the notice is sent. The account will
be closed after the 30-day period unless,
before the end of the 30-day period, the
Administrator receives a correctly
submitted TR SO2 Group 1 allowance
transfer under § 97.622 to the account or
a statement submitted by the authorized
account representative or alternate
authorized account representative
demonstrating to the satisfaction of the
Administrator good cause as to why the
account should not be closed.
(d) Account identification. The
Administrator will assign a unique
identifying number to each account
established under paragraph (a), (b), or
(c) of this section.
(e) Responsibilities of authorized
account representative and alternate
authorized account representative. After
the establishment of a compliance
account or general account, the
Administrator will accept or act on a
submission pertaining to the account,
including, but not limited to,
submissions concerning the deduction
or transfer of TR SO2 Group 1
allowances in the account, only if the
submission has been made, signed, and
certified in accordance with §§ 97.614(a)
and 97.618 or paragraphs (c)(2)(ii) and
(c)(5) of this section.
§ 97.621 Recordation of TR SO2 Group 1
allowance allocations and auction results.
(a) By November 7, 2011, the
Administrator will record in each TR
SO2 Group 1 source’s compliance
account the TR SO2 Group 1 allowances
allocated to the TR SO2 Group 1 units
at the source in accordance with
§ 97.611(a) for the control period in
2012.
(b) By November 7, 2011, the
Administrator will record in each TR
SO2 Group 1 source’s compliance
account the TR SO2 Group 1 allowances
allocated to the TR SO2 Group 1 units
at the source in accordance with
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§ 97.611(a) for the control period in
2013, unless the State in which the
source is located notifies the
Administrator in writing by October 17,
2011 of the State’s intent to submit to
the Administrator a complete SIP
revision by April 1, 2012 meeting the
requirements of § 52.39(d)(1) through (4)
of this chapter.
(1) If, by April 1, 2012, the State does
not submit to the Administrator such
complete SIP revision, the
Administrator will record by April 15,
2012 in each TR SO2 Group 1 source’s
compliance account the TR SO2 Group
1 allowances allocated to the TR SO2
Group 1 units at the source in
accordance with § 97.611(a) for the
control period in 2013.
(2) If the State submits to the
Administrator by April 1, 2012, and the
Administrator approves by October 1,
2012, such complete SIP revision, the
Administrator will record by October 1,
2012 in each TR SO2 Group 1 source’s
compliance account the TR SO2 Group
1 allowances allocated to the TR SO2
Group 1 units at the source as provided
in such approved, complete SIP revision
for the control period in 2013.
(3) If the State submits to the
Administrator by April 1, 2012, and the
Administrator does not approve by
October 1, 2012, such complete SIP
revision, the Administrator will record
by October 1, 2012 in each TR SO2
Group 1 source’s compliance account
the TR SO2 Group 1 allowances
allocated to the TR SO2 Group 1 units
at the source in accordance with
§ 97.611(a) for the control period in
2013.
(c) By July 1, 2013, the Administrator
will record in each TR SO2 Group 1
source’s compliance account the TR SO2
Group 1 allowances allocated to the TR
SO2 Group 1 units at the source, or in
each appropriate Allowance
Management System account the TR
SO2 Group 1 allowances auctioned to
TR SO2 Group 1 units, in accordance
with § 97.611(a), or with a SIP revision
approved under § 52.39(e) or (f) of this
chapter, for the control period in 2014
and 2015.
(d) By July 1, 2014, the Administrator
will record in each TR SO2 Group 1
source’s compliance account the TR SO2
Group 1 allowances allocated to the TR
SO2 Group 1 units at the source, or in
each appropriate Allowance
Management System account the TR
SO2 Group 1 allowances auctioned to
TR SO2 Group 1 units, in accordance
with § 97.611(a), or with a SIP revision
approved under § 52.39(e) or (f) of this
chapter, for the control period in 2016
and 2017.
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(e) By July 1, 2015, the Administrator
will record in each TR SO2 Group 1
source’s compliance account the TR SO2
Group 1 allowances allocated to the TR
SO2 Group 1 units at the source, or in
each appropriate Allowance
Management System account the TR
SO2 Group 1 allowances auctioned to
TR SO2 Group 1 units, in accordance
with § 97.611(a), or with a SIP revision
approved under § 52.39(e) or (f) of this
chapter, for the control period in 2018
and 2019.
(f) By July 1, 2016 and July 1 of each
year thereafter, the Administrator will
record in each TR SO2 Group 1 source’s
compliance account the TR SO2 Group
1 allowances allocated to the TR SO2
Group 1 units at the source, or in each
appropriate Allowance Management
System account the TR SO2 Group 1
allowances auctioned to TR SO2 Group
1 units, in accordance with § 97.611(a),
or with a SIP revision approved under
§ 52.39(e) and (f) of this chapter, for the
control period in the fourth year after
the year of the applicable recordation
deadline under this paragraph.
(g) By August 1, 2012 and August 1
of each year thereafter, the
Administrator will record in each TR
SO2 Group 1 source’s compliance
account the TR SO2 Group 1 allowances
allocated to the TR SO2 Group 1 units
at the source, or in each appropriate
Allowance Management System account
the TR SO2 Group 1 allowances
auctioned to TR SO2 Group 1 units, in
accordance with § 97.612(a)(2) through
(8) and (12), or with a SIP revision
approved under § 52.39(e) and (f) of this
chapter, for the control period in the
year of the applicable recordation
deadline under this paragraph.
(h) By August 1, 2012 and August 1
of each year thereafter, the
Administrator will record in each TR
SO2 Group 1 source’s compliance
account the TR SO2 Group 1 allowances
allocated to the TR SO2 Group 1 units
at the source in accordance with
§ 97.612(b)(2) through (8) and (12) for
the control period in the year of the
applicable recordation deadline under
this paragraph.
(i) By February 15, 2013 and February
15 of each year thereafter, the
Administrator will record in each TR
SO2 Group 1 source’s compliance
account the TR SO2 Group 1 allowances
allocated to the TR SO2 Group 1 units
at the source in accordance with
§ 97.612(a)(9) through (12), for the
control period in the year before the
year of the applicable recordation
deadline under this paragraph.
(j) By the date on which any
allocation or auction results, other than
an allocation or auction results
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48451
described in paragraphs (a) through (i)
of this section, of TR SO2 Group 1
allowances to a recipient is made by or
are submitted to the Administrator in
accordance with § 97.611 or § 97.612 or
with a SIP revision approved under
§ 52.39(e) or (f) of this chapter, the
Administrator will record such
allocation or auction results in the
appropriate Allowance Management
System account.
(k) When recording the allocation or
auction of TR SO2 Group 1 allowances
to a TR SO2 Group 1 unit or other entity
in an Allowance Management System
account, the Administrator will assign
each TR SO2 Group 1 allowance a
unique identification number that will
include digits identifying the year of the
control period for which the TR SO2
Group 1 allowance is allocated or
auctioned.
§ 97.622 Submission of TR SO2 Group 1
allowance transfers.
(a) An authorized account
representative seeking recordation of a
TR SO2 Group 1 allowance transfer shall
submit the transfer to the Administrator.
(b) A TR SO2 Group 1 allowance
transfer shall be correctly submitted if:
(1) The transfer includes the following
elements, in a format prescribed by the
Administrator:
(i) The account numbers established
by the Administrator for both the
transferor and transferee accounts;
(ii) The serial number of each TR SO2
Group 1 allowance that is in the
transferor account and is to be
transferred; and
(iii) The name and signature of the
authorized account representative of the
transferor account and the date signed;
and
(2) When the Administrator attempts
to record the transfer, the transferor
account includes each TR SO2 Group 1
allowance identified by serial number in
the transfer.
§ 97.623 Recordation of TR SO2 Group 1
allowance transfers.
(a) Within 5 business days (except as
provided in paragraph (b) of this
section) of receiving a TR SO2 Group 1
allowance transfer that is correctly
submitted under § 97.622, the
Administrator will record a TR SO2
Group 1 allowance transfer by moving
each TR SO2 Group 1 allowance from
the transferor account to the transferee
account as specified in the transfer.
(b) A TR SO2 Group 1 allowance
transfer to or from a compliance account
that is submitted for recordation after
the allowance transfer deadline for a
control period and that includes any TR
SO2 Group 1 allowances allocated for
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any control period before such
allowance transfer deadline will not be
recorded until after the Administrator
completes the deductions from such
compliance account under § 97.624 for
the control period immediately before
such allowance transfer deadline.
(c) Where a TR SO2 Group 1
allowance transfer is not correctly
submitted under § 97.622, the
Administrator will not record such
transfer.
(d) Within 5 business days of
recordation of a TR SO2 Group 1
allowance transfer under paragraphs (a)
and (b) of the section, the Administrator
will notify the authorized account
representatives of both the transferor
and transferee accounts.
(e) Within 10 business days of receipt
of a TR SO2 Group 1 allowance transfer
that is not correctly submitted under
§ 97.622, the Administrator will notify
the authorized account representatives
of both accounts subject to the transfer
of:
(1) A decision not to record the
transfer, and
(2) The reasons for such nonrecordation.
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§ 97.624 Compliance with TR SO2 Group 1
emissions limitation.
(a) Availability for deduction for
compliance. TR SO2 Group 1 allowances
are available to be deducted for
compliance with a source’s TR SO2
Group 1 emissions limitation for a
control period in a given year only if the
TR SO2 Group 1 allowances:
(1) Were allocated for such control
period or a control period in a prior
year; and
(2) Are held in the source’s
compliance account as of the allowance
transfer deadline for such control
period.
(b) Deductions for compliance. After
the recordation, in accordance with
§ 97.623, of TR SO2 Group 1 allowance
transfers submitted by the allowance
transfer deadline for a control period in
a given year, the Administrator will
deduct from each source’s compliance
account TR SO2 Group 1 allowances
available under paragraph (a) of this
section in order to determine whether
the source meets the TR SO2 Group 1
emissions limitation for such control
period, as follows:
(1) Until the amount of TR SO2 Group
1 allowances deducted equals the
number of tons of total SO2 emissions
from all TR SO2 Group 1 units at the
source for such control period; or
(2) If there are insufficient TR SO2
Group 1 allowances to complete the
deductions in paragraph (b)(1) of this
section, until no more TR SO2 Group 1
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allowances available under paragraph
(a) of this section remain in the
compliance account.
(c)(1) Identification of TR SO2 Group
1 allowances by serial number. The
authorized account representative for a
source’s compliance account may
request that specific TR SO2 Group 1
allowances, identified by serial number,
in the compliance account be deducted
for emissions or excess emissions for a
control period in a given year in
accordance with paragraph (b) or (d) of
this section. In order to be complete,
such request shall be submitted to the
Administrator by the allowance transfer
deadline for such control period and
include, in a format prescribed by the
Administrator, the identification of the
TR SO2 Group 1 source and the
appropriate serial numbers.
(2) First-in, first-out. The
Administrator will deduct TR SO2
Group 1 allowances under paragraph (b)
or (d) of this section from the source’s
compliance account in accordance with
a complete request under paragraph
(c)(1) of this section or, in the absence
of such request or in the case of
identification of an insufficient amount
of TR SO2 Group 1 allowances in such
request, on a first-in, first-out
accounting basis in the following order:
(i) Any TR SO2 Group 1 allowances
that were allocated to the units at the
source and not transferred out of the
compliance account, in the order of
recordation; and then
(ii) Any TR SO2 Group 1 allowances
that were allocated to any unit and
transferred to and recorded in the
compliance account pursuant to this
subpart, in the order of recordation.
(d) Deductions for excess emissions.
After making the deductions for
compliance under paragraph (b) of this
section for a control period in a year in
which the TR SO2 Group 1 source has
excess emissions, the Administrator will
deduct from the source’s compliance
account an amount of TR SO2 Group 1
allowances, allocated for a control
period in a prior year or the control
period in the year of the excess
emissions or in the immediately
following year, equal to two times the
number of tons of the source’s excess
emissions.
(e) Recordation of deductions. The
Administrator will record in the
appropriate compliance account all
deductions from such an account under
paragraphs (b) and (d) of this section.
§ 97.625 Compliance with TR SO2 Group 1
assurance provisions.
(a) Availability for deduction. TR SO2
Group 1 allowances are available to be
deducted for compliance with the TR
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SO2 Group 1 assurance provisions for a
control period in a given year by the
owners and operators of a group of one
or more TR SO2 Group 1 sources and
units in a State (and Indian country
within the borders of such State) only if
the TR SO2 Group 1 allowances:
(1) Were allocated for a control period
in a prior year or the control period in
the given year or in the immediately
following year; and
(2) Are held in the assurance account,
established by the Administrator for
such owners and operators of such
group of TR SO2 Group 1 sources and
units in such State (and Indian country
within the borders of such State) under
paragraph (b)(3) of this section, as of the
deadline established in paragraph (b)(4)
of this section.
(b) Deductions for compliance. The
Administrator will deduct TR SO2
Group 1 allowances available under
paragraph (a) of this section for
compliance with the TR SO2 Group 1
assurance provisions for a State for a
control period in a given year in
accordance with the following
procedures:
(1) By June 1, 2013 and June 1 of each
year thereafter, the Administrator will:
(i) Calculate, for each State (and
Indian country within the borders of
such State), the total SO2 emissions
from all TR SO2 Group 1 units at TR SO2
Group 1 sources in the State (and Indian
country within the borders of such
State) during the control period in the
year before the year of this calculation
deadline and the amount, if any, by
which such total SO2 emissions exceed
the State assurance level as described in
§ 97.606(c)(2)(iii); and
(ii) Promulgate a notice of data
availability of the results of the
calculations required in paragraph
(b)(1)(i) of this section, including
separate calculations of the SO2
emissions from each TR SO2 Group 1
source.
(2) For each notice of data availability
required in paragraph (b)(1)(ii) of this
section and for any State (and Indian
country within the borders of such
State) identified in such notice as
having TR SO2 Group 1 units with total
SO2 emissions exceeding the State
assurance level for a control period in
a given year, as described in
§ 97.606(c)(2)(iii):
(i) By July 1 immediately after the
promulgation of such notice, the
designated representative of each TR
SO2 Group 1 source in each such State
(and Indian country within the borders
of such State) shall submit a statement,
in a format prescribed by the
Administrator, providing for each TR
SO2 Group 1 unit (if any) at the source
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that operates during, but is not allocated
an amount of TR SO2 Group 1
allowances for, such control period, the
unit’s allowable SO2 emission rate for
such control period and, if such rate is
expressed in lb per mmBtu, the unit’s
heat rate.
(ii) By August 1 immediately after the
promulgation of such notice, the
Administrator will calculate, for each
such State (and Indian country within
the borders of such State) and such
control period and each common
designated representative for such
control period for a group of one or
more TR SO2 Group 1 sources and units
in the State (and Indian country within
the borders of such State), the common
designated representative’s share of the
total SO2 emissions from all TR SO2
Group 1 units at TR SO2 Group 1
sources in the State (and Indian country
within the borders of such State), the
common designated representative’s
assurance level, and the amount (if any)
of TR SO2 Group 1 allowances that the
owners and operators of such group of
sources and units must hold in
accordance with the calculation formula
in § 97.606(c)(2)(i) and will promulgate
a notice of data availability of the results
of these calculations.
(iii) The Administrator will provide
an opportunity for submission of
objections to the calculations referenced
by the notice of data availability
required in paragraph (b)(2)(ii) of this
section and the calculations referenced
by the relevant notice of data
availability required in paragraph
(b)(1)(i) of this section.
(A) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations referenced in
the relevant notice required under
paragraph (b)(1)(ii) of this section and
referenced in the notice required under
paragraph (b)(2)(ii) of this section are in
accordance with § 97.606(c)(2)(iii),
§§ 97.606(b) and 97.630 through 97.635,
the definitions of ‘‘common designated
representative’’, ‘‘common designated
representative’s assurance level’’, and
‘‘common designated representative’s
share’’ in § 97.602, and the calculation
formula in § 97.606(c)(2)(i).
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(2)(iii)(A) of this section. By October
1 immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of data availability
of any adjustments that the
Administrator determines to be
necessary and the reasons for accepting
or rejecting any objections submitted in
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accordance with paragraph (b)(2)(iii)(A)
of this section.
(3) For any State (and Indian country
within the borders of such State)
referenced in each notice of data
availability required in paragraph
(b)(2)(iii)(B) of this section as having TR
SO2 Group 1 units with total SO2
emissions exceeding the State assurance
level for a control period in a given year,
the Administrator will establish one
assurance account for each set of owners
and operators referenced, in the notice
of data availability required under
paragraph (b)(2)(iii)(B) of this section, as
all of the owners and operators of a
group of TR SO2 Group 1 sources and
units in the State (and Indian country
within the borders of such State) having
a common designated representative for
such control period and as being
required to hold TR SO2 Group 1
allowances.
(4)(i) As of midnight of November 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(iii)(B) of this section,
the owners and operators described in
paragraph (b)(3) of this section shall
hold in the assurance account
established for them and for the
appropriate TR SO2 Group 1 sources, TR
SO2 Group 1 units, and State (and
Indian country within the borders of
such State) under paragraph (b)(3) of
this section a total amount of TR SO2
Group 1 allowances, available for
deduction under paragraph (a) of this
section, equal to the amount such
owners and operators are required to
hold with regard to such sources, units
and State (and Indian country within
the borders of such State) as calculated
by the Administrator and referenced in
such notice.
(ii) Notwithstanding the allowanceholding deadline specified in paragraph
(b)(4)(i) of this section, if November 1 is
not a business day, then such
allowance-holding deadline shall be
midnight of the first business day
thereafter.
(5) After November 1 (or the date
described in paragraph (b)(4)(ii) of this
section) immediately after the
promulgation of each notice of data
availability required in paragraph
(b)(2)(iii)(B) of this section and after the
recordation, in accordance with
§ 97.623, of TR SO2 Group 1 allowance
transfers submitted by midnight of such
date, the Administrator will determine
whether the owners and operators
described in paragraph (b)(3) of this
section hold, in the assurance account
for the appropriate TR SO2 Group 1
sources, TR SO2 Group 1 units, and
State (and Indian country within the
borders of such State) established under
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48453
paragraph (b)(3) of this section, the
amount of TR SO2 Group 1 allowances
available under paragraph (a) of this
section that the owners and operators
are required to hold with regard to such
sources, units, and State (and Indian
country within the borders of such
State) as calculated by the
Administrator and referenced in the
notice required in paragraph
(b)(2)(iii)(B) of this section.
(6) Notwithstanding any other
provision of this subpart and any
revision, made by or submitted to the
Administrator after the promulgation of
the notice of data availability required
in paragraph (b)(2)(iii)(B) of this section
for a control period in a given year, of
any data used in making the
calculations referenced in such notice,
the amounts of TR SO2 Group 1
allowances that the owners and
operators are required to hold in
accordance with § 97.606(c)(2)(i) for
such control period shall continue to be
such amounts as calculated by the
Administrator and referenced in such
notice required in paragraph
(b)(2)(iii)(B) of this section, except as
follows:
(i) If any such data are revised by the
Administrator as a result of a decision
in or settlement of litigation concerning
such data on appeal under part 78 of
this chapter of such notice, or on appeal
under section 307 of the Clean Air Act
of a decision rendered under part 78 of
this chapter on appeal of such notice,
then the Administrator will use the data
as so revised to recalculate the amounts
of TR SO2 Group 1 allowances that
owners and operators are required to
hold in accordance with the calculation
formula in § 97.606(c)(2)(i) for such
control period with regard to the TR SO2
Group 1 sources, TR SO2 Group 1 units,
and State (and Indian country within
the borders of such State) involved,
provided that such litigation under part
78 of this chapter, or the proceeding
under part 78 of this chapter that
resulted in the decision appealed in
such litigation under section 307 of the
Clean Air Act, was initiated no later
than 30 days after promulgation of such
notice required in paragraph
(b)(2)(iii)(B) of this section.
(ii) If any such data are revised by the
owners and operators of a TR SO2 Group
1 source and TR SO2 Group 1 unit
whose designated representative
submitted such data under paragraph
(b)(2)(i) of this section, as a result of a
decision in or settlement of litigation
concerning such submission, then the
Administrator will use the data as so
revised to recalculate the amounts of TR
SO2 Group 1 allowances that owners
and operators are required to hold in
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accordance with the calculation formula
in § 97.606(c)(2)(i) for such control
period with regard to the TR SO2 Group
1 sources, TR SO2 Group 1 units, and
State (and Indian country within the
borders of such State) involved,
provided that such litigation was
initiated no later than 30 days after
promulgation of such notice required in
paragraph (b)(2)(iii)(B) of this section.
(iii) If the revised data are used to
recalculate, in accordance with
paragraphs (b)(6)(i) and (ii) of this
section, the amount of TR SO2 Group 1
allowances that the owners and
operators are required to hold for such
control period with regard to the TR SO2
Group 1 sources, TR SO2 Group 1 units,
and State (and Indian country within
the borders of such State) involved—
(A) Where the amount of TR SO2
Group 1 allowances that the owners and
operators are required to hold increases
as a result of the use of all such revised
data, the Administrator will establish a
new, reasonable deadline on which the
owners and operators shall hold the
additional amount of TR SO2 Group 1
allowances in the assurance account
established by the Administrator for the
appropriate TR SO2 Group 1 sources, TR
SO2 Group 1 units, and State (and
Indian country within the borders of
such State) under paragraph (b)(3) of
this section. The owners’ and operators’
failure to hold such additional amount,
as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owners’ and operators’ failure
to hold such additional amount, as
required, as of the new deadline shall be
a violation of the Clean Air Act. Each
TR SO2 Group 1 allowance that the
owners and operators fail to hold as
required as of the new deadline, and
each day in such control period, shall be
a separate violation of the Clean Air Act.
(B) For the owners and operators for
which the amount of TR SO2 Group 1
allowances required to be held
decreases as a result of the use of all
such revised data, the Administrator
will record, in all accounts from which
TR SO2 Group 1 allowances were
transferred by such owners and
operators for such control period to the
assurance account established by the
Administrator for the appropriate TR
SO2 Group 1 sources, TR SO2 Group 1
units, and State (and Indian country
within the borders of such State) under
paragraph (b)(3) of this section, a total
amount of the TR SO2 Group 1
allowances held in such assurance
account equal to the amount of the
decrease. If TR SO2 Group 1 allowances
were transferred to such assurance
account from more than one account,
the amount of TR SO2 Group 1
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allowances recorded in each such
transferor account will be in proportion
to the percentage of the total amount of
TR SO2 Group 1 allowances transferred
to such assurance account for such
control period from such transferor
account.
(C) Each TR SO2 Group 1 allowance
held under paragraph (b)(6)(iii)(A) of
this section as a result of recalculation
of requirements under the TR SO2
Group 1 assurance provisions for such
control period must be a TR SO2 Group
1 allowance allocated for a control
period in a year before or the year
immediately following, or in the same
year as, the year of such control period.
§ 97.626
Banking.
(a) A TR SO2 Group 1 allowance may
be banked for future use or transfer in
a compliance account or a general
account in accordance with paragraph
(b) of this section.
(b) Any TR SO2 Group 1 allowance
that is held in a compliance account or
a general account will remain in such
account unless and until the TR SO2
Group 1 allowance is deducted or
transferred under § 97.611(c), § 97.623,
§ 97.624, § 97.625, § 97.627, or § 97.628.
§ 97.627
Account error.
The Administrator may, at his or her
sole discretion and on his or her own
motion, correct any error in any
Allowance Management System
account. Within 10 business days of
making such correction, the
Administrator will notify the authorized
account representative for the account.
§ 97.628 Administrator’s action on
submissions.
(a) The Administrator may review and
conduct independent audits concerning
any submission under the TR SO2
Group 1 Trading Program and make
appropriate adjustments of the
information in the submission.
(b) The Administrator may deduct TR
SO2 Group 1 allowances from or transfer
TR SO2 Group 1 allowances to a
compliance account or an assurance
account, based on the information in a
submission, as adjusted under
paragraph (a)(1) of this section, and
record such deductions and transfers.
§ 97.629
[Reserved]
§ 97.630 General monitoring,
recordkeeping, and reporting requirements.
The owners and operators, and to the
extent applicable, the designated
representative, of a TR SO2 Group 1
unit, shall comply with the monitoring,
recordkeeping, and reporting
requirements as provided in this subpart
and subparts F and G of part 75 of this
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chapter. For purposes of applying such
requirements, the definitions in § 97.602
and in § 72.2 of this chapter shall apply,
the terms ‘‘affected unit,’’ ‘‘designated
representative,’’ and ‘‘continuous
emission monitoring system’’ (or
‘‘CEMS’’) in part 75 of this chapter shall
be deemed to refer to the terms ‘‘TR SO2
Group 1 unit,’’ ‘‘designated
representative,’’ and ‘‘continuous
emission monitoring system’’ (or
‘‘CEMS’’) respectively as defined in
§ 97.602, and the term ‘‘newly affected
unit’’ shall be deemed to mean ‘‘newly
affected TR SO2 Group 1 unit’’. The
owner or operator of a unit that is not
a TR SO2 Group 1 unit but that is
monitored under § 75.16(b)(2) of this
chapter shall comply with the same
monitoring, recordkeeping, and
reporting requirements as a TR SO2
Group 1 unit.
(a) Requirements for installation,
certification, and data accounting. The
owner or operator of each TR SO2 Group
1 unit shall:
(1) Install all monitoring systems
required under this subpart for
monitoring SO2 mass emissions and
individual unit heat input (including all
systems required to monitor SO2
concentration, stack gas moisture
content, stack gas flow rate, CO2 or O2
concentration, and fuel flow rate, as
applicable, in accordance with §§ 75.11
and 75.16 of this chapter);
(2) Successfully complete all
certification tests required under
§ 97.631 and meet all other
requirements of this subpart and part 75
of this chapter applicable to the
monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure
the data from the monitoring systems
under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as
provided in paragraph (e) of this
section, the owner or operator shall
meet the monitoring system certification
and other requirements of paragraphs
(a)(1) and (2) of this section on or before
the following dates and shall record,
report, and quality-assure the data from
the monitoring systems under paragraph
(a)(1) of this section on and after the
following dates.
(1) For the owner or operator of a TR
SO2 Group 1 unit that commences
commercial operation before July 1,
2011, January 1, 2012.
(2) For the owner or operator of a TR
SO2 Group 1 unit that commences
commercial operation on or after July 1,
2011, by the later of the following:
(i) January 1, 2012; or
(ii) 180 calendar days after the date on
which the unit commences commercial
operation.
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(3) The owner or operator of a TR SO2
Group 1 unit for which construction of
a new stack or flue or installation of
add-on SO2 emission controls is
completed after the applicable deadline
under paragraph (b)(1) or (2) of this
section shall meet the requirements of
§§ 75.4(e)(1) through (e)(4) of this
chapter, except that:
(i) Such requirements shall apply to
the monitoring systems required under
§ 97.630 through § 97.635, rather than
the monitoring systems required under
part 75 of this chapter;
(ii) SO2 concentration, stack gas
moisture content, stack gas volumetric
flow rate, and O2 or CO2 concentration
data shall be determined and reported,
rather than the data listed in § 75.4(e)(2)
of this chapter; and
(iii) Any petition for another
procedure under § 75.4(e)(2) of this
chapter shall be submitted under
§ 97.635, rather than § 75.66.
(c) Reporting data. The owner or
operator of a TR SO2 Group 1 unit that
does not meet the applicable
compliance date set forth in paragraph
(b) of this section for any monitoring
system under paragraph (a)(1) of this
section shall, for each such monitoring
system, determine, record, and report
maximum potential (or, as appropriate,
minimum potential) values for SO2
concentration, stack gas flow rate, stack
gas moisture content, fuel flow rate, and
any other parameters required to
determine SO2 mass emissions and heat
input in accordance with § 75.31(b)(2)
or (c)(3) of this chapter or section 2.4 of
appendix D to part 75 of this chapter, as
applicable.
(d) Prohibitions. (1) No owner or
operator of a TR SO2 Group 1 unit shall
use any alternative monitoring system,
alternative reference method, or any
other alternative to any requirement of
this subpart without having obtained
prior written approval in accordance
with § 97.635.
(2) No owner or operator of a TR SO2
Group 1 unit shall operate the unit so
as to discharge, or allow to be
discharged, SO2 to the atmosphere
without accounting for all such SO2 in
accordance with the applicable
provisions of this subpart and part 75 of
this chapter.
(3) No owner or operator of a TR SO2
Group 1 unit shall disrupt the
continuous emission monitoring system,
any portion thereof, or any other
approved emission monitoring method,
and thereby avoid monitoring and
recording SO2 mass discharged into the
atmosphere or heat input, except for
periods of recertification or periods
when calibration, quality assurance
testing, or maintenance is performed in
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accordance with the applicable
provisions of this subpart and part 75 of
this chapter.
(4) No owner or operator of a TR SO2
Group 1 unit shall retire or permanently
discontinue use of the continuous
emission monitoring system, any
component thereof, or any other
approved monitoring system under this
subpart, except under any one of the
following circumstances:
(i) During the period that the unit is
covered by an exemption under § 97.605
that is in effect;
(ii) The owner or operator is
monitoring emissions from the unit with
another certified monitoring system
approved, in accordance with the
applicable provisions of this subpart
and part 75 of this chapter, by the
Administrator for use at that unit that
provides emission data for the same
pollutant or parameter as the retired or
discontinued monitoring system; or
(iii) The designated representative
submits notification of the date of
certification testing of a replacement
monitoring system for the retired or
discontinued monitoring system in
accordance with § 97.631(d)(3)(i).
(e) Long-term cold storage. The owner
or operator of a TR SO2 Group 1 unit is
subject to the applicable provisions of
§ 75.4(d) of this chapter concerning
units in long-term cold storage.
§ 97.631 Initial monitoring system
certification and recertification procedures.
(a) The owner or operator of a TR SO2
Group 1 unit shall be exempt from the
initial certification requirements of this
section for a monitoring system under
§ 97.630(a)(1) if the following conditions
are met:
(1) The monitoring system has been
previously certified in accordance with
part 75 of this chapter; and
(2) The applicable quality-assurance
and quality-control requirements of
§ 75.21 of this chapter and appendices
B and D to part 75 of this chapter are
fully met for the certified monitoring
system described in paragraph (a)(1) of
this section.
(b) The recertification provisions of
this section shall apply to a monitoring
system under § 97.630(a)(1) that is
exempt from initial certification
requirements under paragraph (a) of this
section.
(c) [Reserved]
(d) Except as provided in paragraph
(a) of this section, the owner or operator
of a TR SO2 Group 1 unit shall comply
with the following initial certification
and recertification procedures, for a
continuous monitoring system (i.e., a
continuous emission monitoring system
and an excepted monitoring system
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48455
under appendix D to part 75 of this
chapter) under § 97.630(a)(1). The
owner or operator of a unit that qualifies
to use the low mass emissions excepted
monitoring methodology under § 75.19
of this chapter or that qualifies to use an
alternative monitoring system under
subpart E of part 75 of this chapter shall
comply with the procedures in
paragraph (e) or (f) of this section
respectively.
(1) Requirements for initial
certification. The owner or operator
shall ensure that each continuous
monitoring system under § 97.630(a)(1)
(including the automated data
acquisition and handling system)
successfully completes all of the initial
certification testing required under
§ 75.20 of this chapter by the applicable
deadline in § 97.630(b). In addition,
whenever the owner or operator installs
a monitoring system to meet the
requirements of this subpart in a
location where no such monitoring
system was previously installed, initial
certification in accordance with § 75.20
of this chapter is required.
(2) Requirements for recertification.
Whenever the owner or operator makes
a replacement, modification, or change
in any certified continuous emission
monitoring system under § 97.630(a)(1)
that may significantly affect the ability
of the system to accurately measure or
record SO2 mass emissions or heat input
rate or to meet the quality-assurance and
quality-control requirements of § 75.21
of this chapter or appendix B to part 75
of this chapter, the owner or operator
shall recertify the monitoring system in
accordance with § 75.20(b) of this
chapter. Furthermore, whenever the
owner or operator makes a replacement,
modification, or change to the flue gas
handling system or the unit’s operation
that may significantly change the stack
flow or concentration profile, the owner
or operator shall recertify each
continuous emission monitoring system
whose accuracy is potentially affected
by the change, in accordance with
§ 75.20(b) of this chapter. Examples of
changes to a continuous emission
monitoring system that require
recertification include: Replacement of
the analyzer, complete replacement of
an existing continuous emission
monitoring system, or change in
location or orientation of the sampling
probe or site. Any fuel flowmeter system
under § 97.630(a)(1) is subject to the
recertification requirements in
§ 75.20(g)(6) of this chapter.
(3) Approval process for initial
certification and recertification. For
initial certification of a continuous
monitoring system under § 97.630(a)(1),
paragraphs (d)(3)(i) through (v) of this
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section apply. For recertifications of
such monitoring systems, paragraphs
(d)(3)(i) through (iv) of this section and
the procedures in §§ 75.20(b)(5) and
(g)(7) of this chapter (in lieu of the
procedures in paragraph (d)(3)(v) of this
section) apply, provided that in
applying paragraphs (d)(3)(i) through
(iv) of this section, the words
‘‘certification’’ and ‘‘initial certification’’
are replaced by the word
‘‘recertification’’ and the word
‘‘certified’’ is replaced by the word
‘‘recertified’’.
(i) Notification of certification. The
designated representative shall submit
to the appropriate EPA Regional Office
and the Administrator written notice of
the dates of certification testing, in
accordance with § 97.633.
(ii) Certification application. The
designated representative shall submit
to the Administrator a certification
application for each monitoring system.
A complete certification application
shall include the information specified
in § 75.63 of this chapter.
(iii) Provisional certification date. The
provisional certification date for a
monitoring system shall be determined
in accordance with § 75.20(a)(3) of this
chapter. A provisionally certified
monitoring system may be used under
the TR SO2 Group 1 Trading Program for
a period not to exceed 120 days after
receipt by the Administrator of the
complete certification application for
the monitoring system under paragraph
(d)(3)(ii) of this section. Data measured
and recorded by the provisionally
certified monitoring system, in
accordance with the requirements of
part 75 of this chapter, will be
considered valid quality-assured data
(retroactive to the date and time of
provisional certification), provided that
the Administrator does not invalidate
the provisional certification by issuing a
notice of disapproval within 120 days of
the date of receipt of the complete
certification application by the
Administrator.
(iv) Certification application approval
process. The Administrator will issue a
written notice of approval or
disapproval of the certification
application to the owner or operator
within 120 days of receipt of the
complete certification application under
paragraph (d)(3)(ii) of this section. In the
event the Administrator does not issue
such a notice within such 120-day
period, each monitoring system that
meets the applicable performance
requirements of part 75 of this chapter
and is included in the certification
application will be deemed certified for
use under the TR SO2 Group 1 Trading
Program.
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(A) Approval notice. If the
certification application is complete and
shows that each monitoring system
meets the applicable performance
requirements of part 75 of this chapter,
then the Administrator will issue a
written notice of approval of the
certification application within 120
days of receipt.
(B) Incomplete application notice. If
the certification application is not
complete, then the Administrator will
issue a written notice of incompleteness
that sets a reasonable date by which the
designated representative must submit
the additional information required to
complete the certification application. If
the designated representative does not
comply with the notice of
incompleteness by the specified date,
then the Administrator may issue a
notice of disapproval under paragraph
(d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the
certification application shows that any
monitoring system does not meet the
performance requirements of part 75 of
this chapter or if the certification
application is incomplete and the
requirement for disapproval under
paragraph (d)(3)(iv)(B) of this section is
met, then the Administrator will issue a
written notice of disapproval of the
certification application. Upon issuance
of such notice of disapproval, the
provisional certification is invalidated
by the Administrator and the data
measured and recorded by each
uncertified monitoring system shall not
be considered valid quality-assured data
beginning with the date and hour of
provisional certification (as defined
under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The
Administrator may issue a notice of
disapproval of the certification status of
a monitor in accordance with
§ 97.632(b).
(v) Procedures for loss of certification.
If the Administrator issues a notice of
disapproval of a certification
application under paragraph
(d)(3)(iv)(C) of this section or a notice of
disapproval of certification status under
paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall
substitute the following values, for each
disapproved monitoring system, for
each hour of unit operation during the
period of invalid data specified under
§ 75.20(a)(4)(iii), § 75.20(g)(7), or
§ 75.21(e) of this chapter and continuing
until the applicable date and hour
specified under § 75.20(a)(5)(i) or (g)(7)
of this chapter:
(1) For a disapproved SO2 pollutant
concentration monitor and disapproved
flow monitor, respectively, the
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maximum potential concentration of
SO2 and the maximum potential flow
rate, as defined in sections 2.1.1.1 and
2.1.4.1 of appendix A to part 75 of this
chapter.
(2) For a disapproved moisture
monitoring system and disapproved
diluent gas monitoring system,
respectively, the minimum potential
moisture percentage and either the
maximum potential CO2 concentration
or the minimum potential O2
concentration (as applicable), as defined
in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(3) For a disapproved fuel flowmeter
system, the maximum potential fuel
flow rate, as defined in section 2.4.2.1
of appendix D to part 75 of this chapter.
(B) The designated representative
shall submit a notification of
certification retest dates and a new
certification application in accordance
with paragraphs (d)(3)(i) and (ii) of this
section.
(C) The owner or operator shall repeat
all certification tests or other
requirements that were failed by the
monitoring system, as indicated in the
Administrator’s notice of disapproval,
no later than 30 unit operating days
after the date of issuance of the notice
of disapproval.
(e) The owner or operator of a unit
qualified to use the low mass emissions
(LME) excepted methodology under
§ 75.19 of this chapter shall meet the
applicable certification and
recertification requirements in
§§ 75.19(a)(2) and 75.20(h) of this
chapter. If the owner or operator of such
a unit elects to certify a fuel flowmeter
system for heat input determination, the
owner or operator shall also meet the
certification and recertification
requirements in § 75.20(g) of this
chapter.
(f) The designated representative of
each unit for which the owner or
operator intends to use an alternative
monitoring system approved by the
Administrator under subpart E of part
75 of this chapter shall comply with the
applicable notification and application
procedures of § 75.20(f) of this chapter.
§ 97.632 Monitoring system out-of-control
periods.
(a) General provisions. Whenever any
monitoring system fails to meet the
quality-assurance and quality-control
requirements or data validation
requirements of part 75 of this chapter,
data shall be substituted using the
applicable missing data procedures in
subpart D or appendix D to part 75 of
this chapter.
(b) Audit decertification. Whenever
both an audit of a monitoring system
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and a review of the initial certification
or recertification application reveal that
any monitoring system should not have
been certified or recertified because it
did not meet a particular performance
specification or other requirement under
§ 97.631 or the applicable provisions of
part 75 of this chapter, both at the time
of the initial certification or
recertification application submission
and at the time of the audit, the
Administrator will issue a notice of
disapproval of the certification status of
such monitoring system. For the
purposes of this paragraph, an audit
shall be either a field audit or an audit
of any information submitted to the
Administrator or any State or permitting
authority. By issuing the notice of
disapproval, the Administrator revokes
prospectively the certification status of
the monitoring system. The data
measured and recorded by the
monitoring system shall not be
considered valid quality-assured data
from the date of issuance of the
notification of the revoked certification
status until the date and time that the
owner or operator completes
subsequently approved initial
certification or recertification tests for
the monitoring system. The owner or
operator shall follow the applicable
initial certification or recertification
procedures in § 97.631 for each
disapproved monitoring system.
§ 97.633 Notifications concerning
monitoring.
The designated representative of a TR
SO2 Group 1 unit shall submit written
notice to the Administrator in
accordance with § 75.61 of this chapter.
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§ 97.634
Recordkeeping and reporting.
(a) General provisions. The designated
representative shall comply with all
recordkeeping and reporting
requirements in paragraphs (b) through
(e) of this section, the applicable
recordkeeping and reporting
requirements in subparts F and G of part
75 of this chapter, and the requirements
of § 97.614(a).
(b) Monitoring plans. The owner or
operator of a TR SO2 Group 1 unit shall
comply with requirements of § 75.62 of
this chapter.
(c) Certification applications. The
designated representative shall submit
an application to the Administrator
within 45 days after completing all
initial certification or recertification
tests required under § 97.631, including
the information required under § 75.63
of this chapter.
(d) Quarterly reports. The designated
representative shall submit quarterly
reports, as follows:
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(1) The designated representative
shall report the SO2 mass emissions data
and heat input data for the TR SO2
Group 1 unit, in an electronic quarterly
report in a format prescribed by the
Administrator, for each calendar quarter
beginning with:
(i) For a unit that commences
commercial operation before July 1,
2011, the calendar quarter covering
January 1, 2012 through March 31, 2012;
or
(ii) For a unit that commences
commercial operation on or after July 1,
2011, the calendar quarter
corresponding to the earlier of the date
of provisional certification or the
applicable deadline for initial
certification under § 97.630(b), unless
that quarter is the third or fourth quarter
of 2011, in which case reporting shall
commence in the quarter covering
January 1, 2012 through March 31, 2012.
(2) The designated representative
shall submit each quarterly report to the
Administrator within 30 days after the
end of the calendar quarter covered by
the report. Quarterly reports shall be
submitted in the manner specified in
§ 75.64 of this chapter.
(3) For TR SO2 Group 1 units that are
also subject to the Acid Rain Program,
TR NOX Annual Trading Program, or TR
NOX Ozone Season Trading Program,
quarterly reports shall include the
applicable data and information
required by subparts F through H of part
75 of this chapter as applicable, in
addition to the SO2 mass emission data,
heat input data, and other information
required by this subpart.
(4) The Administrator may review and
conduct independent audits of any
quarterly report in order to determine
whether the quarterly report meets the
requirements of this subpart and part 75
of this chapter, including the
requirement to use substitute data.
(i) The Administrator will notify the
designated representative of any
determination that the quarterly report
fails to meet any such requirements and
specify in such notification any
corrections that the Administrator
believes are necessary to make through
resubmission of the quarterly report and
a reasonable time period within which
the designated representative must
respond. Upon request by the
designated representative, the
Administrator may specify reasonable
extensions of such time period. Within
the time period (including any such
extensions) specified by the
Administrator, the designated
representative shall resubmit the
quarterly report with the corrections
specified by the Administrator, except
to the extent the designated
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representative provides information
demonstrating that a specified
correction is not necessary because the
quarterly report already meets the
requirements of this subpart and part 75
of this chapter that are relevant to the
specified correction.
(ii) Any resubmission of a quarterly
report shall meet the requirements
applicable to the submission of a
quarterly report under this subpart and
part 75 of this chapter, except for the
deadline set forth in paragraph (d)(2) of
this section.
(e) Compliance certification. The
designated representative shall submit
to the Administrator a compliance
certification (in a format prescribed by
the Administrator) in support of each
quarterly report based on reasonable
inquiry of those persons with primary
responsibility for ensuring that all of the
unit’s emissions are correctly and fully
monitored. The certification shall state
that:
(1) The monitoring data submitted
were recorded in accordance with the
applicable requirements of this subpart
and part 75 of this chapter, including
the quality assurance procedures and
specifications; and
(2) For a unit with add-on SO2
emission controls and for all hours
where SO2 data are substituted in
accordance with § 75.34(a)(1) of this
chapter, the add-on emission controls
were operating within the range of
parameters listed in the quality
assurance/quality control program
under appendix B to part 75 of this
chapter and the substitute data values
do not systematically underestimate SO2
emissions.
§ 97.635 Petitions for alternatives to
monitoring, recordkeeping, or reporting
requirements.
(a) The designated representative of a
TR SO2 Group 1 unit may submit a
petition under § 75.66 of this chapter to
the Administrator, requesting approval
to apply an alternative to any
requirement of §§ 97.630 through
97.634.
(b) A petition submitted under
paragraph (a) of this section shall
include sufficient information for the
evaluation of the petition, including, at
a minimum, the following information:
(i) Identification of each unit and
source covered by the petition;
(ii) A detailed explanation of why the
proposed alternative is being suggested
in lieu of the requirement;
(iii) A description and diagram of any
equipment and procedures used in the
proposed alternative;
(iv) A demonstration that the
proposed alternative is consistent with
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the purposes of the requirement for
which the alternative is proposed and
with the purposes of this subpart and
part 75 of this chapter and that any
adverse effect of approving the
alternative will be de minimis; and
(v) Any other relevant information
that the Administrator may require.
(c) Use of an alternative to any
requirement referenced in paragraph (a)
of this section is in accordance with this
subpart only to the extent that the
petition is approved in writing by the
Administrator and that such use is in
accordance with such approval.
77. Part 97 is amended by adding
subpart DDDDD to read as follows:
Subpart DDDDD—TR SO2 Group 2 Trading
Program
Sec.
97.701 Purpose.
97.702 Definitions.
97.703 Measurements, abbreviations, and
acronyms.
97.704 Applicability.
97.705 Retired unit exemption.
97.706 Standard requirements.
97.707 Computation of time.
97.708 Administrative appeal procedures.
97.709 [Reserved]
97.710 State SO2 Group 2 trading budgets,
new unit set-asides, Indian country new
unit set-asides and variability limits.
97.711 Timing requirements for TR SO2
Group 2 allowance allocations.
97.712 TR SO2 Group 2 allowance
allocations to new units.
97.713 Authorization of designated
representative and alternate designated
representative.
97.714 Responsibilities of designated
representative and alternate designated
representative.
97.715 Changing designated representative
and alternate designated representative;
changes in owners and operators.
97.716 Certificate of representation.
97.717 Objections concerning designated
representative and alternate designated
representative.
97.718 Delegation by designated
representative and alternate designated
representative.
97.719 [Reserved]
97.720 Establishment of compliance
accounts and general accounts.
97.721 Recordation of TR SO2 Group 2
allowance allocations.
97.722 Submission of TR SO2 Group 2
allowance transfers.
97.723 Recordation of TR SO2 Group 2
allowance transfers.
97.724 Compliance with TR SO2 Group 2
emissions limitation.
97.725 Compliance with TR SO2 Group 2
assurance provisions.
97.726 Banking.
97.727 Account error.
97.728 Administrator’s action on
submissions.
97.729 [Reserved]
97.730 General monitoring, recordkeeping,
and reporting requirements.
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97.731 Initial monitoring system
certification and recertification
procedures.
97.732 Monitoring system out-of-control
periods.
97.733 Notifications concerning
monitoring.
97.734 Recordkeeping and reporting.
97.735 Petitions for alternatives to
monitoring, recordkeeping, or reporting
requirements.
Subpart DDDDD—TR SO2 Group 2
Trading Program
§ 97.701
Purpose.
This subpart sets forth the general,
designated representative, allowance,
and monitoring provisions for the
Transport Rule (TR) SO2 Group 2
Trading Program, under section 110 of
the Clean Air Act and § 52.39 of this
chapter, as a means of mitigating
interstate transport of fine particulates
and sulfur dioxide.
§ 97.702
Definitions.
The terms used in this subpart shall
have the meanings set forth in this
section as follows:
Acid Rain Program means a multistate SO2 and NOX air pollution control
and emission reduction program
established by the Administrator under
title IV of the Clean Air Act and parts
72 through 78 of this chapter.
Administrator means the
Administrator of the United States
Environmental Protection Agency or the
Director of the Clean Air Markets
Division (or its successor determined by
the Administrator) of the United States
Environmental Protection Agency, the
Administrator’s duly authorized
representative under this subpart.
Allocate or allocation means, with
regard to TR SO2 Group 2 allowances,
the determination by the Administrator,
State, or permitting authority, in
accordance with this subpart and any
SIP revision submitted by the State and
approved by the Administrator under
§ 52.39(g), (h), or (i) of this chapter, of
the amount of such TR SO2 Group 2
allowances to be initially credited, at no
cost to the recipient, to:
(1) A TR SO2 Group 2 unit;
(2) A new unit set-aside;
(3) An Indian country new unit setaside; or
(4) An entity not listed in paragraphs
(1) through (3) of this definition;
(5) Provided that, if the
Administrator, State, or permitting
authority initially credits, to a TR SO2
Group 2 unit qualifying for an initial
credit, a credit in the amount of zero TR
SO2 Group 2 allowances, the TR SO2
Group 2 unit will be treated as being
allocated an amount (i.e., zero) of TR
SO2 Group 2 allowances.
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Allowable SO2 emission rate means,
for a unit, the most stringent State or
federal SO2 emission rate limit (in lb/
MWhr or, if in lb/mmBtu, converted to
lb/MWhr by multiplying it by the unit’s
heat rate in mmBtu/MWhr) that is
applicable to the unit and covers the
longest averaging period not exceeding
one year.
Allowance Management System
means the system by which the
Administrator records allocations,
deductions, and transfers of TR SO2
Group 2 allowances under the TR SO2
Group 2 Trading Program. Such
allowances are allocated, recorded,
held, deducted, or transferred only as
whole allowances.
Allowance Management System
account means an account in the
Allowance Management System
established by the Administrator for
purposes of recording the allocation,
holding, transfer, or deduction of TR
SO2 Group 2 allowances.
Allowance transfer deadline means,
for a control period in a given year,
midnight of March 1 (if it is a business
day), or midnight of the first business
day thereafter (if March 1 is not a
business day), immediately after such
control period and is the deadline by
which a TR SO2 Group 2 allowance
transfer must be submitted for
recordation in a TR SO2 Group 2
source’s compliance account in order to
be available for use in complying with
the source’s TR SO2 Group 2 emissions
limitation for such control period in
accordance with §§ 97.706 and 97.724.
Alternate designated representative
means, for a TR SO2 Group 2 source and
each TR SO2 Group 2 unit at the source,
the natural person who is authorized by
the owners and operators of the source
and all such units at the source, in
accordance with this subpart, to act on
behalf of the designated representative
in matters pertaining to the TR SO2
Group 2 Trading Program. If the TR SO2
Group 2 source is also subject to the
Acid Rain Program, TR NOX Annual
Trading Program, or TR NOX Ozone
Season Trading Program, then this
natural person shall be the same natural
person as the alternate designated
representative, as defined in the
respective program.
Assurance account means an
Allowance Management System
account, established by the
Administrator under § 97.725(b)(3) for
certain owners and operators of a group
of one or more TR SO2 Group 2 sources
and units in a given State (and Indian
country within the borders of such
State), in which are held TR SO2 Group
2 allowances available for use for a
control period in a given year in
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complying with the TR SO2 Group 2
assurance provisions in accordance with
§§ 97.706 and 97.725.
Authorized account representative
means, for a general account, the natural
person who is authorized, in accordance
with this subpart, to transfer and
otherwise dispose of TR SO2 Group 2
allowances held in the general account
and, for a TR SO2 Group 2 source’s
compliance account, the designated
representative of the source.
Automated data acquisition and
handling system or DAHS means the
component of the continuous emission
monitoring system, or other emissions
monitoring system approved for use
under this subpart, designed to interpret
and convert individual output signals
from pollutant concentration monitors,
flow monitors, diluent gas monitors,
and other component parts of the
monitoring system to produce a
continuous record of the measured
parameters in the measurement units
required by this subpart.
Biomass means—
(1) Any organic material grown for the
purpose of being converted to energy;
(2) Any organic byproduct of
agriculture that can be converted into
energy; or
(3) Any material that can be converted
into energy and is nonmerchantable for
other purposes, that is segregated from
other material that is nonmerchantable
for other purposes, and that is;
(i) A forest-related organic resource,
including mill residues, precommercial
thinnings, slash, brush, or byproduct
from conversion of trees to
merchantable material; or
(ii) A wood material, including
pallets, crates, dunnage, manufacturing
and construction materials (other than
pressure-treated, chemically-treated, or
painted wood products), and landscape
or right-of-way tree trimmings.
Boiler means an enclosed fossil- or
other-fuel-fired combustion device used
to produce heat and to transfer heat to
recirculating water, steam, or other
medium.
Bottoming-cycle unit means a unit in
which the energy input to the unit is
first used to produce useful thermal
energy, where at least some of the reject
heat from the useful thermal energy
application or process is then used for
electricity production.
Business day means a day that does
not fall on a weekend or a federal
holiday.
Certifying official means a natural
person who is:
(1) For a corporation, a president,
secretary, treasurer, or vice-president of
the corporation in charge of a principal
business function or any other person
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who performs similar policy- or
decision-making functions for the
corporation;
(2) For a partnership or sole
proprietorship, a general partner or the
proprietor respectively; or
(3) For a local government entity or
State, federal, or other public agency, a
principal executive officer or ranking
elected official.
Clean Air Act means the Clean Air
Act, 42 U.S.C. 7401, et seq.
Coal means ‘‘coal’’ as defined in
§ 72.2 of this chapter.
Coal-derived fuel means any fuel
(whether in a solid, liquid, or gaseous
state) produced by the mechanical,
thermal, or chemical processing of coal.
Cogeneration system means an
integrated group, at a source, of
equipment (including a boiler, or
combustion turbine, and a steam turbine
generator) designed to produce useful
thermal energy for industrial,
commercial, heating, or cooling
purposes and electricity through the
sequential use of energy.
Cogeneration unit means a stationary,
fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine that
is a topping-cycle unit or a bottomingcycle unit:
(1) Operating as part of a cogeneration
system; and
(2) Producing on an annual average
basis—
(i) For a topping-cycle unit,
(A) Useful thermal energy not less
than 5 percent of total energy output;
and
(B) Useful power that, when added to
one-half of useful thermal energy
produced, is not less than 42.5 percent
of total energy input, if useful thermal
energy produced is 15 percent or more
of total energy output, or not less than
45 percent of total energy input, if
useful thermal energy produced is less
than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful
power not less than 45 percent of total
energy input;
(3) Provided that the requirements in
paragraph (2) of this definition shall not
apply to a calendar year referenced in
paragraph (2) of this definition during
which the unit did not operate at all;
(4) Provided that the total energy
input under paragraphs (2)(i)(B) and
(2)(ii) of this definition shall equal the
unit’s total energy input from all fuel,
except biomass if the unit is a boiler;
and
(5) Provided that, if, throughout its
operation during the 12-month period or
a calendar year referenced in paragraph
(2) of this definition, a unit is operated
as part of a cogeneration system and the
cogeneration system meets on a system-
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wide basis the requirement in paragraph
(2)(i)(B) or (2)(ii) of this definition, the
unit shall be deemed to meet such
requirement during that 12-month
period or calendar year.
Combustion turbine means an
enclosed device comprising:
(1) If the device is simple cycle, a
compressor, a combustor, and a turbine
and in which the flue gas resulting from
the combustion of fuel in the combustor
passes through the turbine, rotating the
turbine; and
(2) If the device is combined cycle,
the equipment described in paragraph
(1) of this definition and any associated
duct burner, heat recovery steam
generator, and steam turbine.
Commence commercial operation
means, with regard to a unit:
(1) To have begun to produce steam,
gas, or other heated medium used to
generate electricity for sale or use,
including test generation, except as
provided in § 97.705.
(i) For a unit that is a TR SO2 Group
2 unit under § 97.704 on the later of
January 1, 2005 or the date the unit
commences commercial operation as
defined in the introductory text of
paragraph (1) of this definition and that
subsequently undergoes a physical
change or is moved to a new location or
source, such date shall remain the date
of commencement of commercial
operation of the unit, which shall
continue to be treated as the same unit.
(ii) For a unit that is a TR SO2 Group
2 unit under § 97.704 on the later of
January 1, 2005 or the date the unit
commences commercial operation as
defined in the introductory text of
paragraph (1) of this definition and that
is subsequently replaced by a unit at the
same or a different source, such date
shall remain the replaced unit’s date of
commencement of commercial
operation, and the replacement unit
shall be treated as a separate unit with
a separate date for commencement of
commercial operation as defined in
paragraph (1) or (2) of this definition as
appropriate.
(2) Notwithstanding paragraph (1) of
this definition and except as provided
in § 97.705, for a unit that is not a TR
SO2 Group 2 unit under § 97.704 on the
later of January 1, 2005 or the date the
unit commences commercial operation
as defined in introductory text of
paragraph (1) of this definition, the
unit’s date for commencement of
commercial operation shall be the date
on which the unit becomes a TR SO2
Group 2 unit under § 97.704.
(i) For a unit with a date for
commencement of commercial
operation as defined in the introductory
text of paragraph (2) of this definition
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and that subsequently undergoes a
physical change or is moved to a
different location or source, such date
shall remain the date of commencement
of commercial operation of the unit,
which shall continue to be treated as the
same unit.
(ii) For a unit with a date for
commencement of commercial
operation as defined in the introductory
text of paragraph (2) of this definition
and that is subsequently replaced by a
unit at the same or a different source,
such date shall remain the replaced
unit’s date of commencement of
commercial operation, and the
replacement unit shall be treated as a
separate unit with a separate date for
commencement of commercial
operation as defined in paragraph (1) or
(2) of this definition as appropriate.
Common designated representative
means, with regard to a control period
in a given year, a designated
representative where, as of April 1
immediately after the allowance transfer
deadline for such control period, the
same natural person is authorized under
§§ 97.713(a) and 97.715(a) as the
designated representative for a group of
one or more TR SO2 Group 2 sources
and units located in a State (and Indian
country within the borders of such
State).
Common designated representative’s
assurance level means, with regard to a
specific common designated
representative and a State (and Indian
country within the borders of such
State) and control period in a given year
for which the State assurance level is
exceeded as described in
§ 97.706(c)(2)(iii), the common
designated representative’s share of the
State SO2 Group 2 trading budget with
the variability limit for the State for
such control period.
Common designated representative’s
share means, with regard to a specific
common designated representative for a
control period in a given year:
(1) With regard to a total amount of
SO2 emissions from all TR SO2 Group 2
units in a State (and Indian country
within the borders of such State) during
such control period, the total tonnage of
SO2 emissions during such control
period from a group of one or more TR
SO2 Group 2 units located in such State
(and such Indian country) and having
the common designated representative
for such control period;
(2) With regard to a State SO2 Group
2 trading budget with the variability
limit for such control period, the
amount (rounded to the nearest
allowance) equal to the sum of the total
amount of TR SO2 Group 2 allowances
allocated for such control period to a
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group of one or more TR SO2 Group 2
units located in the State (and Indian
country within the borders of such
State) and having the common
designated representative for such
control period and of the total amount
of TR SO2 Group 2 allowances
purchased by an owner or operator of
such TR SO2 Group 2 units in an
auction for such control period and
submitted by the State or the permitting
authority to the Administrator for
recordation in the compliance accounts
for such TR SO2 Group 2 units in
accordance with the TR SO2 Group 2
allowance auction provisions in a SIP
revision approved by the Administrator
under § 52.39(h) or (i) of this chapter,
multiplied by the sum of the State SO2
Group 2 trading budget under
§ 97.710(a) and the State’s variability
limit under § 97.710(b) for such control
period and divided by such State SO2
Group 2 trading budget;
(3) Provided that, in the case of a unit
that operates during, but has no amount
of TR SO2 Group 2 allowances allocated
under §§ 97.711 and 97.712 for, such
control period, the unit shall be treated,
solely for purposes of this definition, as
being allocated an amount (rounded to
the nearest allowance) of TR SO2 Group
2 allowances for such control period
equal to the unit’s allowable SO2
emission rate applicable to such control
period, multiplied by a capacity factor
of 0.85 (if the unit is a boiler combusting
any amount of coal or coal-derived fuel
during such control period), 0.24 (if the
unit is a simple combustion turbine
during such control period), 0.67 (if the
unit is a combined cycle turbine during
such control period), 0.74 (if the unit is
an integrated coal gasification combined
cycle unit during such control period),
or 0.36 (for any other unit), multiplied
by the unit’s maximum hourly load as
reported in accordance with this subpart
and by 8,760 hours/control period, and
divided by 2,000 lb/ton.
Common stack means a single flue
through which emissions from 2 or
more units are exhausted.
Compliance account means an
Allowance Management System
account, established by the
Administrator for a TR SO2 Group 2
source under this subpart, in which any
TR SO2 Group 2 allowance allocations
to the TR SO2 Group 2 units at the
source are recorded and in which are
held any TR SO2 Group 2 allowances
available for use for a control period in
a given year in complying with the
source’s TR SO2 Group 2 emissions
limitation in accordance with §§ 97.706
and 97.724.
Continuous emission monitoring
system or CEMS means the equipment
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required under this subpart to sample,
analyze, measure, and provide, by
means of readings recorded at least once
every 15 minutes and using an
automated data acquisition and
handling system (DAHS), a permanent
record of SO2 emissions, stack gas
volumetric flow rate, stack gas moisture
content, and O2 or CO2 concentration (as
applicable), in a manner consistent with
part 75 of this chapter and §§ 97.730
through 97.735. The following systems
are the principal types of continuous
emission monitoring systems:
(1) A flow monitoring system,
consisting of a stack flow rate monitor
and an automated data acquisition and
handling system and providing a
permanent, continuous record of stack
gas volumetric flow rate, in standard
cubic feet per hour (scfh);
(2) A SO2 monitoring system,
consisting of a SO2 pollutant
concentration monitor and an
automated data acquisition and
handling system and providing a
permanent, continuous record of SO2
emissions, in parts per million (ppm);
(3) A moisture monitoring system, as
defined in § 75.11(b)(2) of this chapter
and providing a permanent, continuous
record of the stack gas moisture content,
in percent H2O;
(4) A CO2 monitoring system,
consisting of a CO2 pollutant
concentration monitor (or an O2 monitor
plus suitable mathematical equations
from which the CO2 concentration is
derived) and an automated data
acquisition and handling system and
providing a permanent, continuous
record of CO2 emissions, in percent CO2;
and
(5) An O2 monitoring system,
consisting of an O2 concentration
monitor and an automated data
acquisition and handling system and
providing a permanent, continuous
record of O2, in percent O2.
Control period means the period
starting January 1 of a calendar year,
except as provided in § 97.706(c)(3), and
ending on December 31 of the same
year, inclusive.
Designated representative means, for
a TR SO2 Group 2 source and each TR
SO2 Group 2 unit at the source, the
natural person who is authorized by the
owners and operators of the source and
all such units at the source, in
accordance with this subpart, to
represent and legally bind each owner
and operator in matters pertaining to the
TR SO2 Group 2 Trading Program. If the
TR SO2 Group 2 source is also subject
to the Acid Rain Program, TR NOX
Annual Trading Program, or TR NOX
Ozone Season Trading Program, then
this natural person shall be the same
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natural person as the designated
representative, as defined in the
respective program.
Emissions means air pollutants
exhausted from a unit or source into the
atmosphere, as measured, recorded, and
reported to the Administrator by the
designated representative, and as
modified by the Administrator:
(1) In accordance with this subpart;
and
(2) With regard to a period before the
unit or source is required to measure,
record, and report such air pollutants in
accordance with this subpart, in
accordance with part 75 of this chapter.
Excess emissions means any ton of
emissions from the TR SO2 Group 2
units at a TR SO2 Group 2 source during
a control period in a given year that
exceeds the TR SO2 Group 2 emissions
limitation for the source for such control
period.
Fossil fuel means—
(1) Natural gas, petroleum, coal, or
any form of solid, liquid, or gaseous fuel
derived from such material; or
(2) For purposes of applying the
limitation on ‘‘average annual fuel
consumption of fossil fuel’’ in
§§ 97.704(b)(2)(i)(B) and (ii), natural gas,
petroleum, coal, or any form of solid,
liquid, or gaseous fuel derived from
such material for the purpose of creating
useful heat.
Fossil-fuel-fired means, with regard to
a unit, combusting any amount of fossil
fuel in 2005 or any calendar year
thereafter.
General account means an Allowance
Management System account,
established under this subpart, that is
not a compliance account or an
assurance account.
Generator means a device that
produces electricity.
Gross electrical output means, for a
unit, electricity made available for use,
including any such electricity used in
the power production process (which
process includes, but is not limited to,
any on-site processing or treatment of
fuel combusted at the unit and any onsite emission controls).
Heat input means, for a unit for a
specified period of time, the product (in
mmBtu/time) of the gross calorific value
of the fuel (in mmBtu/lb) fed into the
unit multiplied by the fuel feed rate (in
lb of fuel/time), as measured, recorded,
and reported to the Administrator by the
designated representative and as
modified by the Administrator in
accordance with this subpart and
excluding the heat derived from
preheated combustion air, recirculated
flue gases, or exhaust.
Heat input rate means, for a unit, the
amount of heat input (in mmBtu)
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divided by unit operating time (in hr)
or, for a unit and a specific fuel, the
amount of heat input attributed to the
fuel (in mmBtu) divided by the unit
operating time (in hr) during which the
unit combusts the fuel.
Heat rate means, for a unit, the unit’s
maximum design heat input (in Btu/hr),
divided by the product of 1,000,000
Btu/mmBtu and the unit’s maximum
hourly load.
Indian country means ‘‘Indian
country’’ as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power
contractual arrangement means a unit
participation power sales agreement
under which a utility or industrial
customer reserves, or is entitled to
receive, a specified amount or
percentage of nameplate capacity and
associated energy generated by any
specified unit and pays its proportional
amount of such unit’s total costs,
pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less
than 30 years, including contracts that
permit an election for early termination;
or
(3) For a period no less than 25 years
or 70 percent of the economic useful life
of the unit determined as of the time the
unit is built, with option rights to
purchase or release some portion of the
nameplate capacity and associated
energy generated by the unit at the end
of the period.
Maximum design heat input means,
for a unit, the maximum amount of fuel
per hour (in Btu/hr) that the unit is
capable of combusting on a steady state
basis as of the initial installation of the
unit as specified by the manufacturer of
the unit.
Monitoring system means any
monitoring system that meets the
requirements of this subpart, including
a continuous emission monitoring
system, an alternative monitoring
system, or an excepted monitoring
system under part 75 of this chapter.
Nameplate capacity means, starting
from the initial installation of a
generator, the maximum electrical
generating output (in MWe, rounded to
the nearest tenth) that the generator is
capable of producing on a steady state
basis and during continuous operation
(when not restricted by seasonal or
other deratings) as of such installation
as specified by the manufacturer of the
generator or, starting from the
completion of any subsequent physical
change in the generator resulting in an
increase in the maximum electrical
generating output that the generator is
capable of producing on a steady state
basis and during continuous operation
(when not restricted by seasonal or
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other deratings), such increased
maximum amount (in MWe, rounded to
the nearest tenth) as of such completion
as specified by the person conducting
the physical change.
Natural gas means ‘‘natural gas’’ as
defined in § 72.2 of this chapter.
Newly affected TR SO2 Group 2 unit
means a unit that was not a TR SO2
Group 2 unit when it began operating
but that thereafter becomes a TR SO2
Group 2 unit.
Operate or operation means, with
regard to a unit, to combust fuel.
Operator means, for a TR SO2 Group
2 source or a TR SO2 Group 2 unit at
a source respectively, any person who
operates, controls, or supervises a TR
SO2 Group 2 unit at the source or the
TR SO2 Group 2 unit and shall include,
but not be limited to, any holding
company, utility system, or plant
manager of such source or unit.
Owner means, for a TR SO2 Group 2
source or a TR SO2 Group 2 unit at a
source respectively, any of the following
persons:
(1) Any holder of any portion of the
legal or equitable title in a TR SO2
Group 2 unit at the source or the TR SO2
Group 2 unit;
(2) Any holder of a leasehold interest
in a TR SO2 Group 2 unit at the source
or the TR SO2 Group 2 unit, provided
that, unless expressly provided for in a
leasehold agreement, ‘‘owner’’ shall not
include a passive lessor, or a person
who has an equitable interest through
such lessor, whose rental payments are
not based (either directly or indirectly)
on the revenues or income from such TR
SO2 Group 2 unit; and
(3) Any purchaser of power from a TR
SO2 Group 2 unit at the source or the
TR SO2 Group 2 unit under a life-of-theunit, firm power contractual
arrangement.
Permanently retired means, with
regard to a unit, a unit that is
unavailable for service and that the
unit’s owners and operators do not
expect to return to service in the future.
Permitting authority means
‘‘permitting authority’’ as defined in
§§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity
means, for a unit, 33 percent of the
unit’s maximum design heat input,
divided by 3,413 Btu/kWh, divided by
1,000 kWh/MWh, and multiplied by
8,760 hr/yr.
Receive or receipt of means, when
referring to the Administrator, to come
into possession of a document,
information, or correspondence
(whether sent in hard copy or by
authorized electronic transmission), as
indicated in an official log, or by a
notation made on the document,
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information, or correspondence, by the
Administrator in the regular course of
business.
Recordation, record, or recorded
means, with regard to TR SO2 Group 2
allowances, the moving of TR SO2
Group 2 allowances by the
Administrator into, out of, or between
Allowance Management System
accounts, for purposes of allocation,
auction, transfer, or deduction.
Reference method means any direct
test method of sampling and analyzing
for an air pollutant as specified in
§ 75.22 of this chapter.
Replacement, replace, or replaced
means, with regard to a unit, the
demolishing of a unit, or the permanent
retirement and permanent disabling of a
unit, and the construction of another
unit (the replacement unit) to be used
instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from
electricity production in a useful
thermal energy application or process;
or
(2) The use of reject heat from useful
thermal energy application or process in
electricity production.
Serial number means, for a TR SO2
Group 2 allowance, the unique
identification number assigned to each
TR SO2 Group 2 allowance by the
Administrator.
Solid waste incineration unit means a
stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion
turbine that is a ‘‘solid waste
incineration unit’’ as defined in section
129(g)(1) of the Clean Air Act.
Source means all buildings,
structures, or installations located in
one or more contiguous or adjacent
properties under common control of the
same person or persons. This definition
does not change or otherwise affect the
definition of ‘‘major source’’, ‘‘stationary
source’’, or ‘‘source’’ as set forth and
implemented in a title V operating
permit program or any other program
under the Clean Air Act.
State means one of the States that is
subject to the TR SO2 Group 2 Trading
Program pursuant to § 52.39(a), (c), (g),
(h), and (i) of this chapter.
Submit or serve means to send or
transmit a document, information, or
correspondence to the person specified
in accordance with the applicable
regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or
transmission and delivery;
(4) Provided that compliance with any
‘‘submission’’ or ‘‘service’’ deadline
shall be determined by the date of
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dispatch, transmission, or mailing and
not the date of receipt.
Topping-cycle unit means a unit in
which the energy input to the unit is
first used to produce useful power,
including electricity, where at least
some of the reject heat from the
electricity production is then used to
provide useful thermal energy.
Total energy input means, for a unit,
total energy of all forms supplied to the
unit, excluding energy produced by the
unit. Each form of energy supplied shall
be measured by the lower heating value
of that form of energy calculated as
follows:
LHV = HHV ¥ 10.55(W + 9H)
Where:
LHV = lower heating value of the form of
energy in Btu/lb,
HHV = higher heating value of the form of
energy in Btu/lb,
W = weight % of moisture in the form of
energy, and
H = weight % of hydrogen in the form of
energy.
Total energy output means, for a unit,
the sum of useful power and useful
thermal energy produced by the unit.
TR NOX Annual Trading Program
means a multi-state NOX air pollution
control and emission reduction program
established in accordance with subpart
AAAAA of this part and § 52.38(a) of
this chapter (including such a program
that is revised in a SIP revision
approved by the Administrator under
§ 52.38(a)(3) or (4) of this chapter or that
is established in a SIP revision approved
by the Administrator under § 52.38(a)(5)
of this chapter), as a means of mitigating
interstate transport of fine particulates
and NOX.
TR NOX Ozone Season Trading
Program means a multi-state NOX air
pollution control and emission
reduction program established in
accordance with subpart BBBBB of this
part and § 52.38(b) of this chapter
(including such a program that is
revised in a SIP revision approved by
the Administrator under § 52.38(b)(3) or
(4) of this chapter or that is established
in a SIP revision approved by the
Administrator under § 52.38(b)(5) of this
chapter), as a means of mitigating
interstate transport of ozone and NOX.
TR SO2 Group 2 allowance means a
limited authorization issued and
allocated or auctioned by the
Administrator under this subpart, or by
a State or permitting authority under a
SIP revision approved by the
Administrator under § 52.39(g), (h), or
(i) of this chapter, to emit one ton of SO2
during a control period of the specified
calendar year for which the
authorization is allocated or auctioned
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or of any calendar year thereafter under
the TR SO2 Group 2 Trading Program.
TR SO2 Group 2 allowance deduction
or deduct TR SO2 Group 2 allowances
means the permanent withdrawal of TR
SO2 Group 2 allowances by the
Administrator from a compliance
account (e.g., in order to account for
compliance with the TR SO2 Group 2
emissions limitation) or from an
assurance account (e.g., in order to
account for compliance with the
assurance provisions under §§ 97.706
and 97.725).
TR SO2 Group 2 allowances held or
hold TR SO2 Group 2 allowances means
the TR SO2 Group 2 allowances treated
as included in an Allowance
Management System account as of a
specified point in time because at that
time they:
(1) Have been recorded by the
Administrator in the account or
transferred into the account by a
correctly submitted, but not yet
recorded, TR SO2 Group 2 allowance
transfer in accordance with this subpart;
and
(2) Have not been transferred out of
the account by a correctly submitted,
but not yet recorded, TR SO2 Group 2
allowance transfer in accordance with
this subpart.
TR SO2 Group 2 emissions limitation
means, for a TR SO2 Group 2 source, the
tonnage of SO2 emissions authorized in
a control period by the TR SO2 Group
2 allowances available for deduction for
the source under § 97.724(a) for such
control period.
TR SO2 Group 2 source means a
source that includes one or more TR
SO2 Group 2 units.
TR SO2 Group 2 Trading Program
means a multi-state SO2 air pollution
control and emission reduction program
established in accordance with this
subpart and § 52.39(a), (c), and (g)
through (k) of this chapter (including
such a program that is revised in a SIP
revision approved by the Administrator
under § 52.39(g) or (h) of this chapter or
that is established in a SIP revision
approved by the Administrator under
§ 52.39(i) of this chapter), as a means of
mitigating interstate transport of fine
particulates and SO2.
TR SO2 Group 2 unit means a unit
that is subject to the TR SO2 Group 2
Trading Program under § 97.704.
Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired
combustion turbine, or other stationary,
fossil-fuel-fired combustion device. A
unit that undergoes a physical change or
is moved to a different location or
source shall continue to be treated as
the same unit. A unit (the replaced unit)
that is replaced by another unit (the
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replacement unit) at the same or a
different source shall continue to be
treated as the same unit, and the
replacement unit shall be treated as a
separate unit.
Unit operating day means, with
regard to a unit, a calendar day in which
the unit combusts any fuel.
Unit operating hour or hour of unit
operation means, with regard to a unit,
an hour in which the unit combusts any
fuel.
Useful power means, with regard to a
unit, electricity or mechanical energy
that the unit makes available for use,
excluding any such energy used in the
power production process (which
process includes, but is not limited to,
any on-site processing or treatment of
fuel combusted at the unit and any onsite emission controls).
Useful thermal energy means thermal
energy that is:
(1) Made available to an industrial or
commercial process (not a power
production process), excluding any heat
contained in condensate return or
makeup water;
(2) Used in a heating application (e.g.,
space heating or domestic hot water
heating); or
(3) Used in a space cooling
application (i.e., in an absorption
chiller).
Utility power distribution system
means the portion of an electricity grid
owned or operated by a utility and
dedicated to delivering electricity to
customers.
§ 97.703 Measurements, abbreviations,
and acronyms.
Measurements, abbreviations, and
acronyms used in this subpart are
defined as follows:
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Btu—British thermal unit
CO2—carbon dioxide
H2O—water
hr—hour
kW—kilowatt electrical
kWh—kilowatt hour
lb—pound
mmBtu—million Btu
MWe—megawatt electrical
MWh—megawatt hour
NOX—nitrogen oxides
O2—oxygen
ppm—parts per million
scfh—standard cubic feet per hour
SO2—sulfur dioxide
yr—year
§ 97.704
Applicability.
(a) Except as provided in paragraph
(b) of this section:
(1) The following units in a State (and
Indian country within the borders of
such State) shall be TR SO2 Group 2
units, and any source that includes one
or more such units shall be a TR SO2
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Group 2 source, subject to the
requirements of this subpart: Any
stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion
turbine serving at any time, on or after
January 1, 2005, a generator with
nameplate capacity of more than 25
MWe producing electricity for sale.
(2) If a stationary boiler or stationary
combustion turbine that, under
paragraph (a)(1) of this section, is not a
TR SO2 Group 2 unit begins to combust
fossil fuel or to serve a generator with
nameplate capacity of more than 25
MWe producing electricity for sale, the
unit shall become a TR SO2 Group 2
unit as provided in paragraph (a)(1) of
this section on the first date on which
it both combusts fossil fuel and serves
such generator.
(b) Any unit in a State (and Indian
country within the borders of such
State) that otherwise is a TR SO2 Group
2 unit under paragraph (a) of this
section and that meets the requirements
set forth in paragraph (b)(1)(i) or (2)(i) of
this section shall not be a TR SO2 Group
2 unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit
throughout the later of 2005 or the
12-month period starting on the date the
unit first produces electricity and
continuing to qualify as a cogeneration
unit throughout each calendar year
ending after the later of 2005 or such
12-month period; and
(B) Not supplying in 2005 or any
calendar year thereafter more than onethird of the unit’s potential electric
output capacity or 219,000 MWh,
whichever is greater, to any utility
power distribution system for sale.
(ii) If, after qualifying under
paragraph (b)(1)(i) of this section as not
being a TR SO2 Group 2 unit, a unit
subsequently no longer meets all the
requirements of paragraph (b)(1)(i) of
this section, the unit shall become a TR
SO2 Group 2 unit starting on the earlier
of January 1 after the first calendar year
during which the unit first no longer
qualifies as a cogeneration unit or
January 1 after the first calendar year
during which the unit no longer meets
the requirements of paragraph
(b)(1)(i)(B) of this section. The unit shall
thereafter continue to be a TR SO2
Group 2 unit.
(2)(i) Any unit:
(A) Qualifying as a solid waste
incineration unit throughout the later of
2005 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit
throughout each calendar year ending
after the later of 2005 or such 12-month
period; and
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48463
(B) With an average annual fuel
consumption of fossil fuel for the first
3 consecutive calendar years of
operation starting no earlier than 2005
of less than 20 percent (on a Btu basis)
and an average annual fuel consumption
of fossil fuel for any 3 consecutive
calendar years thereafter of less than 20
percent (on a Btu basis).
(ii) If, after qualifying under
paragraph (b)(2)(i) of this section as not
being a TR SO2 Group 2 unit, a unit
subsequently no longer meets all the
requirements of paragraph (b)(1)(i) of
this section, the unit shall become a TR
SO2 Group 2 unit starting on the earlier
of January 1 after the first calendar year
during which the unit first no longer
qualifies as a solid waste incineration
unit or January 1 after the first 3
consecutive calendar years after 2005
for which the unit has an average
annual fuel consumption of fossil fuel of
20 percent or more. The unit shall
thereafter continue to be a TR SO2
Group 2 unit.
(c) A certifying official of an owner or
operator of any unit or other equipment
may submit a petition (including any
supporting documents) to the
Administrator at any time for a
determination concerning the
applicability, under paragraphs (a) and
(b) of this section or a SIP revision
approved under § 52.39(h) or (i) of this
chapter, of the TR SO2 Group 2 Trading
Program to the unit or other equipment.
(1) Petition content. The petition shall
be in writing and include the
identification of the unit or other
equipment and the relevant facts about
the unit or other equipment. The
petition and any other documents
provided to the Administrator in
connection with the petition shall
include the following certification
statement, signed by the certifying
official: ‘‘I am authorized to make this
submission on behalf of the owners and
operators of the unit or other equipment
for which the submission is made. I
certify under penalty of law that I have
personally examined, and am familiar
with, the statements and information
submitted in this document and all its
attachments. Based on my inquiry of
those individuals with primary
responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(2) Response. The Administrator will
issue a written response to the petition
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and may request supplemental
information determined by the
Administrator to be relevant to such
petition. The Administrator’s
determination concerning the
applicability, under paragraphs (a) and
(b) of this section, of the TR SO2 Group
2 Trading Program to the unit or other
equipment shall be binding on any State
or permitting authority unless the
Administrator determines that the
petition or other documents or
information provided in connection
with the petition contained significant,
relevant errors or omissions.
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§ 97.705
Retired unit exemption.
(a)(1) Any TR SO2 Group 2 unit that
is permanently retired shall be exempt
from § 97.706(b) and (c)(1), § 97.724,
and §§ 97.730 through 97.735.
(2) The exemption under paragraph
(a)(1) of this section shall become
effective the day on which the TR SO2
Group 2 unit is permanently retired.
Within 30 days of the unit’s permanent
retirement, the designated
representative shall submit a statement
to the Administrator. The statement
shall state, in a format prescribed by the
Administrator, that the unit was
permanently retired on a specified date
and will comply with the requirements
of paragraph (b) of this section.
(b) Special provisions. (1) A unit
exempt under paragraph (a) of this
section shall not emit any SO2, starting
on the date that the exemption takes
effect.
(2) For a period of 5 years from the
date the records are created, the owners
and operators of a unit exempt under
paragraph (a) of this section shall retain,
at the source that includes the unit,
records demonstrating that the unit is
permanently retired. The 5-year period
for keeping records may be extended for
cause, at any time before the end of the
period, in writing by the Administrator.
The owners and operators bear the
burden of proof that the unit is
permanently retired.
(3) The owners and operators and, to
the extent applicable, the designated
representative of a unit exempt under
paragraph (a) of this section shall
comply with the requirements of the TR
SO2 Group 2 Trading Program
concerning all periods for which the
exemption is not in effect, even if such
requirements arise, or must be complied
with, after the exemption takes effect.
(4) A unit exempt under paragraph (a)
of this section shall lose its exemption
on the first date on which the unit
resumes operation. Such unit shall be
treated, for purposes of applying
allocation, monitoring, reporting, and
recordkeeping requirements under this
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subpart, as a unit that commences
commercial operation on the first date
on which the unit resumes operation.
§ 97.706
Standard requirements.
(a) Designated representative
requirements. The owners and operators
shall comply with the requirement to
have a designated representative, and
may have an alternate designated
representative, in accordance with
§§ 97.713 through 97.718.
(b) Emissions monitoring, reporting,
and recordkeeping requirements. (1)
The owners and operators, and the
designated representative, of each TR
SO2 Group 2 source and each TR SO2
Group 2 unit at the source shall comply
with the monitoring, reporting, and
recordkeeping requirements of §§ 97.730
through 97.735.
(2) The emissions data determined in
accordance with §§ 97.730 through
97.735 shall be used to calculate
allocations of TR SO2 Group 2
allowances under §§ 97.711(a)(2) and (b)
and 97.712 and to determine
compliance with the TR SO2 Group 2
emissions limitation and assurance
provisions under paragraph (c) of this
section, provided that, for each
monitoring location from which mass
emissions are reported, the mass
emissions amount used in calculating
such allocations and determining such
compliance shall be the mass emissions
amount for the monitoring location
determined in accordance with
§§ 97.730 through 97.735 and rounded
to the nearest ton, with any fraction of
a ton less than 0.50 being deemed to be
zero.
(c) SO2 emissions requirements. (1)
TR SO2 Group 2 emissions limitation. (i)
As of the allowance transfer deadline for
a control period in a given year, the
owners and operators of each TR SO2
Group 2 source and each TR SO2 Group
2 unit at the source shall hold, in the
source’s compliance account, TR SO2
Group 2 allowances available for
deduction for such control period under
§ 97.724(a) in an amount not less than
the tons of total SO2 emissions for such
control period from all TR SO2 Group 2
units at the source.
(ii) If total SO2 emissions during a
control period in a given year from the
TR SO2 Group 2 units at a TR SO2
Group 2 source are in excess of the TR
SO2 Group 2 emissions limitation set
forth in paragraph (c)(1)(i) of this
section, then:
(A) The owners and operators of the
source and each TR SO2 Group 2 unit
at the source shall hold the TR SO2
Group 2 allowances required for
deduction under § 97.724(d); and
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(B) The owners and operators of the
source and each TR SO2 Group 2 unit
at the source shall pay any fine, penalty,
or assessment or comply with any other
remedy imposed, for the same
violations, under the Clean Air Act, and
each ton of such excess emissions and
each day of such control period shall
constitute a separate violation of this
subpart and the Clean Air Act.
(2) TR SO2 Group 2 assurance
provisions. (i) If total SO2 emissions
during a control period in a given year
from all TR SO2 Group 2 units at TR SO2
Group 2 sources in a State (and Indian
country within the borders of such
State) exceed the State assurance level,
then the owners and operators of such
sources and units in each group of one
or more sources and units having a
common designated representative for
such control period, where the common
designated representative’s share of
such SO2 emissions during such control
period exceeds the common designated
representative’s assurance level for the
State and such control period, shall
hold (in the assurance account
established for the owners and operators
of such group) TR SO2 Group 2
allowances available for deduction for
such control period under § 97.725(a) in
an amount equal to two times the
product (rounded to the nearest whole
number), as determined by the
Administrator in accordance with
§ 97.725(b), of multiplying—
(A) The quotient of the amount by
which the common designated
representative’s share of such SO2
emissions exceeds the common
designated representative’s assurance
level divided by the sum of the
amounts, determined for all common
designated representatives for such
sources and units in the State (and
Indian country within the borders of
such State) for such control period, by
which each common designated
representative’s share of such SO2
emissions exceeds the respective
common designated representative’s
assurance level; and
(B) The amount by which total SO2
emissions from all TR SO2 Group 2
units at TR SO2 Group 2 sources in the
State (and Indian country within the
borders of such State) for such control
period exceed the State assurance level.
(ii) The owners and operators shall
hold the TR SO2 Group 2 allowances
required under paragraph (c)(2)(i) of this
section, as of midnight of November 1
(if it is a business day), or midnight of
the first business day thereafter (if
November 1 is not a business day),
immediately after such control period.
(iii) Total SO2 emissions from all TR
SO2 Group 2 units at TR SO2 Group 2
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sources in a State (and Indian country
within the borders of such State) during
a control period in a given year exceed
the State assurance level if such total
SO2 emissions exceed the sum, for such
control period, of the State SO2 Group
2 trading budget under § 97.710(a) and
the State’s variability limit under
§ 97.710(b).
(iv) It shall not be a violation of this
subpart or of the Clean Air Act if total
SO2 emissions from all TR SO2 Group 2
units at TR SO2 Group 2 sources in a
State (and Indian country within the
borders of such State) during a control
period exceed the State assurance level
or if a common designated
representative’s share of total SO2
emissions from the TR SO2 Group 2
units at TR SO2 Group 2 sources in a
State (and Indian country within the
borders of such State) during a control
period exceeds the common designated
representative’s assurance level.
(v) To the extent the owners and
operators fail to hold TR SO2 Group 2
allowances for a control period in a
given year in accordance with
paragraphs (c)(2)(i) through (iii) of this
section,
(A) The owners and operators shall
pay any fine, penalty, or assessment or
comply with any other remedy imposed
under the Clean Air Act; and
(B) Each TR SO2 Group 2 allowance
that the owners and operators fail to
hold for such control period in
accordance with paragraphs (c)(2)(i)
through (iii) of this section and each day
of such control period shall constitute a
separate violation of this subpart and
the Clean Air Act.
(3) Compliance periods. A TR SO2
Group 2 unit shall be subject to the
requirements under paragraphs (c)(1)
and (c)(2) of this section for the control
period starting on the later of January 1,
2012 or the deadline for meeting the
unit’s monitor certification
requirements under § 97.730(b) and for
each control period thereafter.
(4) Vintage of allowances held for
compliance. (i) A TR SO2 Group 2
allowance held for compliance with the
requirements under paragraph (c)(1)(i)
of this section for a control period in a
given year must be a TR SO2 Group 2
allowance that was allocated for such
control period or a control period in a
prior year.
(ii) A TR SO2 Group 2 allowance held
for compliance with the requirements
under paragraphs (c)(1)(ii)(A) and (2)(i)
through (iii) of this section for a control
period in a given year must be a TR SO2
Group 2 allowance that was allocated
for a control period in a prior year or the
control period in the given year or in the
immediately following year.
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(5) Allowance Management System
requirements. Each TR SO2 Group 2
allowance shall be held in, deducted
from, or transferred into, out of, or
between Allowance Management
System accounts in accordance with
this subpart.
(6) Limited authorization. A TR SO2
Group 2 allowance is a limited
authorization to emit one ton of SO2
during the control period in one year.
Such authorization is limited in its use
and duration as follows:
(i) Such authorization shall only be
used in accordance with the TR SO2
Group 2 Trading Program; and
(ii) Notwithstanding any other
provision of this subpart, the
Administrator has the authority to
terminate or limit the use and duration
of such authorization to the extent the
Administrator determines is necessary
or appropriate to implement any
provision of the Clean Air Act.
(7) Property right. A TR SO2 Group 2
allowance does not constitute a property
right.
(d) Title V permit requirements. (1) No
title V permit revision shall be required
for any allocation, holding, deduction,
or transfer of TR SO2 Group 2
allowances in accordance with this
subpart.
(2) A description of whether a unit is
required to monitor and report SO2
emissions using a continuous emission
monitoring system (under subpart H of
part 75 of this chapter), an excepted
monitoring system (under appendices D
and E to part 75 of this chapter), a low
mass emissions excepted monitoring
methodology (under § 75.19 of this
chapter), or an alternative monitoring
system (under subpart E of part 75 of
this chapter) in accordance with
§§ 97.730 through 97.735 may be added
to, or changed in, a title V permit using
minor permit modification procedures
in accordance with §§ 70.7(e)(2) and
71.7(e)(1) of this chapter, provided that
the requirements applicable to the
described monitoring and reporting (as
added or changed, respectively) are
already incorporated in such permit.
This paragraph explicitly provides that
the addition of, or change to, a unit’s
description as described in the prior
sentence is eligible for minor permit
modification procedures in accordance
with §§ 70.7(e)(2)(i)(B) and
71.7(e)(1)(i)(B) of this chapter.
(e) Additional recordkeeping and
reporting requirements. (1) Unless
otherwise provided, the owners and
operators of each TR SO2 Group 2
source and each TR SO2 Group 2 unit
at the source shall keep on site at the
source each of the following documents
(in hardcopy or electronic format) for a
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48465
period of 5 years from the date the
document is created. This period may
be extended for cause, at any time
before the end of 5 years, in writing by
the Administrator.
(i) The certificate of representation
under § 97.716 for the designated
representative for the source and each
TR SO2 Group 2 unit at the source and
all documents that demonstrate the
truth of the statements in the certificate
of representation; provided that the
certificate and documents shall be
retained on site at the source beyond
such 5-year period until such certificate
of representation and documents are
superseded because of the submission of
a new certificate of representation under
§ 97.716 changing the designated
representative.
(ii) All emissions monitoring
information, in accordance with this
subpart.
(iii) Copies of all reports, compliance
certifications, and other submissions
and all records made or required under,
or to demonstrate compliance with the
requirements of, the TR SO2 Group 2
Trading Program.
(2) The designated representative of a
TR SO2 Group 2 source and each TR
SO2 Group 2 unit at the source shall
make all submissions required under
the TR SO2 Group 2 Trading Program,
except as provided in § 97.718. This
requirement does not change, create an
exemption from, or or otherwise affect
the responsible official submission
requirements under a title V operating
permit program in parts 70 and 71 of
this chapter.
(f) Liability. (1) Any provision of the
TR SO2 Group 2 Trading Program that
applies to a TR SO2 Group 2 source or
the designated representative of a TR
SO2 Group 2 source shall also apply to
the owners and operators of such source
and of the TR SO2 Group 2 units at the
source.
(2) Any provision of the TR SO2
Group 2 Trading Program that applies to
a TR SO2 Group 2 unit or the designated
representative of a TR SO2 Group 2 unit
shall also apply to the owners and
operators of such unit.
(g) Effect on other authorities. No
provision of the TR SO2 Group 2
Trading Program or exemption under
§ 97.705 shall be construed as
exempting or excluding the owners and
operators, and the designated
representative, of a TR SO2 Group 2
source or TR SO2 Group 2 unit from
compliance with any other provision of
the applicable, approved State
implementation plan, a federally
enforceable permit, or the Clean Air Act.
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§ 97.707
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Computation of time.
(a) Unless otherwise stated, any time
period scheduled, under the TR SO2
Group 2 Trading Program, to begin on
the occurrence of an act or event shall
begin on the day the act or event occurs.
(b) Unless otherwise stated, any time
period scheduled, under the TR SO2
Group 2 Trading Program, to begin
before the occurrence of an act or event
shall be computed so that the period
ends the day before the act or event
occurs.
(c) Unless otherwise stated, if the final
day of any time period, under the TR
SO2 Group 2 Trading Program, is not a
business day, the time period shall be
extended to the next business day.
§ 97.708 Administrative appeal
procedures.
The administrative appeal procedures
for decisions of the Administrator under
the TR SO2 Group 2 Trading Program
are set forth in part 78 of this chapter.
§ 97.709
[Reserved]
§ 97.710 State SO2 Group 2 trading
budgets, new unit set-asides, Indian
country new unit set-aside, and variability
limits.
(a) The State SO2 Group 2 trading
budgets, new unit set-asides, and Indian
country new unit set-asides for
allocations of TR SO2 Group 2
allowances for the control periods in
2012 and thereafter are as follows:
SO2 Group 2 trading budget (tons) *
for 2012 and 2013
New unit set-aside
(tons) for 2012 and
2013
Indian country new
unit set-aside (tons)
for 2012 and 2013
216,033
158,527
41,528
41,981
65,052
88,620
243,954
4,321
3,171
789
798
2,537
1,683
11,954
................................
................................
42
42
65
89
244
SO2 Group 2 trading budget (tons) *
for 2014 and
thereafter
State
New unit set-aside
(tons) for 2014 and
thereafter
Indian country new
unit set-aside (tons)
for 2014 and
thereafter
213,258
95,231
41,528
41,981
65,052
88,620
243,954
4,265
1,905
789
798
2,537
1,683
11,954
................................
................................
42
42
65
89
244
Alabama ...............................................................................................................
Georgia ................................................................................................................
Kansas .................................................................................................................
Minnesota ............................................................................................................
Nebraska ..............................................................................................................
South Carolina .....................................................................................................
Texas ...................................................................................................................
State
Alabama ...............................................................................................................
Georgia ................................................................................................................
Kansas .................................................................................................................
Minnesota ............................................................................................................
Nebraska ..............................................................................................................
South Carolina .....................................................................................................
Texas ...................................................................................................................
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-aside and does not include the
variability limit.
(b) The States’ variability limits for
the State SO2 Group 2 trading budgets
for the control periods in 2012 and
thereafter are as follows:
Variability limits
for 2012 and 2013
State
Alabama ...........................................................................................................................................
Georgia ............................................................................................................................................
Kansas .............................................................................................................................................
Minnesota ........................................................................................................................................
Nebraska ..........................................................................................................................................
South Carolina .................................................................................................................................
Texas ...............................................................................................................................................
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§ 97.711 Timing requirements for TR SO2
Group 2 allowance allocations.
(a) Existing units. (1) TR SO2 Group 2
allowances are allocated, for the control
periods in 2012 and each year
thereafter, as provided in a notice of
data availability issued by the
Administrator. Providing an allocation
to a unit in such notice does not
constitute a determination that the unit
is a TR SO2 Group 2 unit, and not
providing an allocation to a unit in such
notice does not constitute a
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determination that the unit is not a TR
SO2 Group 2 unit.
(2) Notwithstanding paragraph (a)(1)
of this section, if a unit provided an
allocation in the notice of data
availability issued under paragraph
(a)(1) of this section does not operate,
starting after 2011, during the control
period in two consecutive years, such
unit will not be allocated the TR SO2
Group 2 allowances provided in such
notice for the unit for the control
periods in the fifth year after the first
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38,886
28,535
7,475
7,557
11,709
15,952
43,912
Variability limits
for 2014 and
thereafter
38,386
17,142
7,475
7,557
11,709
15,952
43,912
such year and in each year after that
fifth year. All TR SO2 Group 2
allowances that would otherwise have
been allocated to such unit will be
allocated to the new unit set-aside for
the State where such unit is located and
for the respective years involved. If such
unit resumes operation, the
Administrator will allocate TR SO2
Group 2 allowances to the unit in
accordance with paragraph (b) of this
section.
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(b) New units. (1) New unit set-asides.
(i) By June 1, 2012 and June 1 of each
year thereafter, the Administrator will
calculate the TR SO2 Group 2 allowance
allocation to each TR SO2 Group 2 unit
in a State, in accordance with
§ 97.712(a)(2) through (7) and (12), for
the control period in the year of the
applicable calculation deadline under
this paragraph and will promulgate a
notice of data availability of the results
of the calculations.
(ii) For each notice of data availability
required in paragraph (b)(1)(i) of this
section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(1)(i) of this section and shall be
limited to addressing whether the
calculations (including the
identification of the TR SO2 Group 2
units) are in accordance with
§ 97.712(a)(2) through (7) and (12) and
§§ 97.706(b)(2) and 97.730 through
97.735.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(1)(ii)(A) of this section. By August 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(1)(i) of this section, the
Administrator will promulgate a notice
of data availability of any adjustments
that the Administrator determines to be
necessary with regard to allocations
under § 97.712(a)(2) through (7) and (12)
and the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(1)(ii)(A)
of this section.
(iii) If the new unit set-aside for such
control period contains any TR SO2
Group 2 allowances that have not been
allocated in the applicable notice of data
availability required in paragraph
(b)(1)(ii) of this section, the
Administrator will promulgate, by
December 15 immediately after such
notice, a notice of data availability that
identifies any TR SO2 Group 2 units that
commenced commercial operation
during the period starting January 1 of
the year before the year of such control
period and ending November 30 of year
of such control period.
(iv) For each notice of data
availability required in paragraph
(b)(1)(iii) of this section, the
Administrator will provide an
opportunity for submission of objections
to the identification of TR SO2 annual
units in such notice.
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(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(1)(iii) of this section and shall be
limited to addressing whether the
identification of TR SO2 annual units in
such notice is in accordance with
paragraph (b)(1)(iii) of this section.
(B) The Administrator will adjust the
identification of TR SO2 Group 2 units
in the each notice of data availability
required in paragraph (b)(1)(iii) of this
section to the extent necessary to ensure
that it is in accordance with paragraph
(b)(1)(iii) of this section and will
calculate the TR SO2 Group 2 allowance
allocation to each TR SO2 Group 2 unit
in accordance with § 97.712(a)(9), (10),
and (12) and §§ 97.706(b)(2) and 97.730
through 97.735. By February 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(1)(iii) of this section,
the Administrator will promulgate a
notice of data availability of any
adjustments of the identification of TR
SO2 Group 2 units that the
Administrator determines to be
necessary, the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(1)(iv)(A)
of this section, and the results of such
calculations.
(v) To the extent any TR SO2 Group
2 allowances are added to the new unit
set-aside after promulgation of each
notice of data availability required in
paragraph (b)(1)(iv) of this section, the
Administrator will promulgate
additional notices of data availability, as
deemed appropriate, of the allocation of
such TR SO2 Group 2 allowances in
accordance with § 97.712(a)(10).
(2) Indian country new unit setasides. (i) By June 1, 2012 and June 1
of each year thereafter, the
Administrator will calculate the TR SO2
Group 2 allowance allocation to each TR
SO2 Group 2 unit in Indian country
within the borders of a State, in
accordance with § 97.712(b)(2) through
(7) and (12), for the control period in the
year of the applicable calculation
deadline under this paragraph and will
promulgate a notice of data availability
of the results of the calculations.
(ii) For each notice of data availability
required in paragraph (b)(2)(i) of this
section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(2)(i) of this section and shall be
limited to addressing whether the
calculations (including the
identification of the TR SO2 Group 2
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48467
units) are in accordance with
§ 97.712(b)(2) through (7) and (12) and
§§ 97.706(b)(2) and 97.730 through
97.735.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(2)(ii)(A) of this section. By August 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(i) of this section, the
Administrator will promulgate a notice
of data availability of any adjustments
that the Administrator determines to be
necessary with regard to allocations
under § 97.712(b)(2) through (7) and (12)
and the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(2)(ii)(A)
of this section.
(iii) If the Indian country new unit
set-aside for such control period
contains any TR SO2 Group 2
allowances that have not been allocated
in the applicable notice of data
availability required in paragraph
(b)(2)(ii) of this section, the
Administrator will promulgate, by
December 15 immediately after such
notice, a notice of data availability that
identifies any TR SO2 Group 2 units that
commenced commercial operation
during the period starting January 1 of
the year before the year of such control
period and ending November 30 of year
of such control period.
(iv) For each notice of data
availability required in paragraph
(b)(2)(iii) of this section, the
Administrator will provide an
opportunity for submission of objections
to the identification of TR SO2 annual
units in such notice.
(A) Objections shall be submitted by
the deadline specified in each notice of
data availability required in paragraph
(b)(2)(iii) of this section and shall be
limited to addressing whether the
identification of TR SO2 annual units in
such notice is in accordance with
paragraph (b)(2)(iii) of this section.
(B) The Administrator will adjust the
identification of TR SO2 Group 2 units
in the each notice of data availability
required in paragraph (b)(2)(iii) of this
section to the extent necessary to ensure
that it is in accordance with paragraph
(b)(2)(iii) of this section and will
calculate the TR SO2 Group 2 allowance
allocation to each TR SO2 Group 2 unit
in accordance with § 97.712(b)(9), (10),
and (12) and §§ 97.706(b)(2) and 97.730
through 97.735. By February 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(iii) of this section,
the Administrator will promulgate a
notice of data availability of any
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adjustments of the identification of TR
SO2 Group 2 units that the
Administrator determines to be
necessary, the reasons for accepting or
rejecting any objections submitted in
accordance with paragraph (b)(2)(iv)(A)
of this section, and the results of such
calculations.
(v) To the extent any TR SO2 Group
2 allowances are added to the Indian
country new unit set-aside after
promulgation of each notice of data
availability required in paragraph
(b)(2)(iv) of this section, the
Administrator will promulgate
additional notices of data availability, as
deemed appropriate, of the allocation of
such TR SO2 Group 2 allowances in
accordance with § 97.712(b)(10).
(c) Units incorrectly allocated TR SO2
Group 2 allowances. (1) For each control
period in 2012 and thereafter, if the
Administrator determines that TR SO2
Group 2 allowances were allocated
under paragraph (a) of this section, or
under a provision of a SIP revision
approved § 52.39(g), (h), or (i) of this
chapter, where such control period and
the recipient are covered by the
provisions of paragraph (c)(1)(i) of this
section or were allocated under
§ 97.712(a)(2) through (7), (9), and (12)
and (b)(2) through (7), (9), and (12), or
under a provision of a SIP revision
approved § 52.39(h) or (i) of this
chapter, where such control period and
the recipient are covered by the
provisions of paragraph (c)(1)(ii) of this
section, then the Administrator will
notify the designated representative of
the recipient and will act in accordance
with the procedures set forth in
paragraphs (c)(2) through (5) of this
section:
(i)(A) The recipient is not actually a
TR SO2 Group 2 unit under § 97.704 as
of January 1, 2012 and is allocated TR
SO2 Group 2 allowances for such
control period or, in the case of an
allocation under a provision of a SIP
revision approved under § 52.39(g), (h),
or (i) of this chapter, the recipient is not
actually a TR SO2 Group 2 unit as of
January 1, 2012 and is allocated TR SO2
Group 2 allowances for such control
period that the SIP revision provides
should be allocated only to recipients
that are TR SO2 Group 2 units as of
January 1, 2012; or
(B) The recipient is not located as of
January 1 of the control period in the
State from whose SO2 Group 2 trading
budget the TR SO2 Group 2 allowances
allocated under paragraph (a) of this
section, or under a provision of a SIP
revision approved under § 52.39(g), (h),
or (i) of this chapter, were allocated for
such control period.
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Jkt 223001
(ii) The recipient is not actually a TR
SO2 Group 2 unit under § 97.704 as of
January 1 of such control period and is
allocated TR SO2 Group 2 allowances
for such control period or, in the case
of an allocation under a provision of a
SIP revision approved under § 52.39(g),
(h), or (i) of this chapter, the recipient
is not actually a TR SO2 Group 2 unit
as of January 1 of such control period
and is allocated TR SO2 Group 2
allowances for such control period that
the SIP revision provides should be
allocated only to recipients that are TR
SO2 Group 2 units as of January 1 of
such control period.
(2) Except as provided in paragraph
(c)(3) or (4) of this section, the
Administrator will not record such TR
SO2 Group 2 allowances under § 97.721.
(3) If the Administrator already
recorded such TR SO2 Group 2
allowances under § 97.721 and if the
Administrator makes the determination
under paragraph (c)(1) of this section
before making deductions for the source
that includes such recipient under
§ 97.724(b) for such control period, then
the Administrator will deduct from the
account in which such TR SO2 Group 2
allowances were recorded an amount of
TR SO2 Group 2 allowances allocated
for the same or a prior control period
equal to the amount of such already
recorded TR SO2 Group 2 allowances.
The authorized account representative
shall ensure that there are sufficient TR
SO2 Group 2 allowances in such
account for completion of the
deduction.
(4) If the Administrator already
recorded such TR SO2 Group 2
allowances under § 97.721 and if the
Administrator makes the determination
under paragraph (c)(1) of this section
after making deductions for the source
that includes such recipient under
§ 97.724(b) for such control period, then
the Administrator will not make any
deduction to take account of such
already recorded TR SO2 Group 2
allowances.
(5)(i) With regard to the TR SO2 Group
2 allowances that are not recorded, or
that are deducted as an incorrect
allocation, in accordance with
paragraphs (c)(2) and (3) of this section
for a recipient under paragraph (c)(1)(i)
of this section, the Administrator will:
(A) Transfer such TR SO2 Group 2
allowances to the new unit set-aside for
such control period for the State from
whose SO2 Group 2 trading budget the
TR SO2 Group 2 allowances were
allocated; or
(B) If the State has a SIP revision
approved under § 52.39(h) or (i)
covering such control period, include
such TR SO2 Group 2 allowances in the
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Frm 00262
Fmt 4701
Sfmt 4700
portion of the State SO2 Group 2 trading
budget that may be allocated for such
control period in accordance with such
SIP revision.
(ii) With regard to the TR SO2 Group
2 allowances that were not allocated
from the Indian country new unit setaside for such control period and that
are not recorded, or that are deducted as
an incorrect allocation, in accordance
with paragraphs (c)(2) and (3) of this
section for a recipient under paragraph
(c)(1)(ii) of this paragraph, the
Administrator will:
(A) Transfer such TR SO2 Group 2
allowances to the new unit set-aside for
such control period; or
(B) If the State has a SIP revision
approved under § 52.39(h) or (i)
covering such control period, include
such TR SO2 Group 2 allowances in the
portion of the State SO2 Group 2 trading
budget that may be allocated for such
control period in accordance with such
SIP revision.
(iii) With regard to the TR SO2 Group
2 allowances that were allocated from
the Indian country new unit set-aside
for such control period and that are not
recorded, or that are deducted as an
incorrect allocation, in accordance with
paragraphs (c)(2) and (3) of this section
for a recipient under paragraph (c)(1)(ii)
of this paragraph, the Administrator will
transfer such TR SO2 Group 2
allowances to the Indian country new
unit set-aside for such control period.
§ 97.712 TR SO2 Group 2 allowance
allocations to new units.
(a) For each control period in 2012
and thereafter and for the TR SO2 Group
2 units in each State, the Administrator
will allocate TR SO2 Group 2
allowances to the TR SO2 Group 2 units
as follows:
(1) The TR SO2 Group 2 allowances
will be allocated to the following TR
SO2 Group 2 units, except as provided
in paragraph (a)(10) of this section:
(i) TR SO2 Group 2 units that are not
allocated an amount of TR SO2 Group 2
allowances in the notice of data
availability issued under § 97.711(a)(1);
(ii) TR SO2 Group 2 units whose
allocation of an amount of TR SO2
Group 2 allowances for such control
period in the notice of data availability
issued under § 97.711(a)(1) is covered
by § 97.711(c)(2) or (3);
(iii) TR SO2 Group 2 units that are
allocated an amount of TR SO2 Group 2
allowances for such control period in
the notice of data availability issued
under § 97.711(a)(1), which allocation is
terminated for such control period
pursuant to § 97.711(a)(2), and that
operate during the control period
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immediately preceding such control
period; or
(iv) For purposes of paragraph (a)(9)
of this section, TR SO2 Group 2 units
under § 97.711(c)(1)(ii) whose allocation
of an amount of TR SO2 Group 2
allowances for such control period in
the notice of data availability issued
under § 97.711(b)(1)(ii)(B) is covered by
§ 97.711(c)(2) or (3).
(2) The Administrator will establish a
separate new unit set-aside for the State
for each such control period. Each such
new unit set-aside will be allocated TR
SO2 Group 2 allowances in an amount
equal to the applicable amount of tons
of SO2 emissions as set forth in
§ 97.710(a) and will be allocated
additional TR SO2 Group 2 allowances
(if any) in accordance with
§§ 97.711(a)(2) and (c)(5) and paragraph
(b)(10) of this section.
(3) The Administrator will determine,
for each TR SO2 Group 2 unit described
in paragraph (a)(1) of this section, an
allocation of TR SO2 Group 2
allowances for the later of the following
control periods and for each subsequent
control period:
(i) The control period in 2012;
(ii) The first control period after the
control period in which the TR SO2
Group 2 unit commences commercial
operation;
(iii) For a unit described in paragraph
(a)(1)(ii) of this section, the first control
period in which the TR SO2 Group 2
unit operates in the State after operating
in another jurisdiction and for which
the unit is not already allocated one or
more TR SO2 Group 2 allowances; and
(iv) For a unit described in paragraph
(a)(1)(iii) of this section, the first control
period after the control period in which
the unit resumes operation.
(4)(i) The allocation to each TR SO2
annual unit described in paragraph
(a)(1)(i) through (iii) of this section and
for each control period described in
paragraph (a)(3) of this section will be
an amount equal to the unit’s total tons
of SO2 emissions during the
immediately preceding control period.
(ii) The Administrator will adjust the
allocation amount in paragraph (a)(4)(i)
in accordance with paragraphs (a)(5)
through (7) and (12) of this section.
(5) The Administrator will calculate
the sum of the TR SO2 Group 2
allowances determined for all such TR
SO2 Group 2 units under paragraph
(a)(4)(i) of this section in the State for
such control period.
(6) If the amount of TR SO2 Group 2
allowances in the new unit set-aside for
the State for such control period is
greater than or equal to the sum under
paragraph (a)(5) of this section, then the
Administrator will allocate the amount
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Jkt 223001
of TR SO2 Group 2 allowances
determined for each such TR SO2 Group
2 unit under paragraph (a)(4)(i) of this
section.
(7) If the amount of TR SO2 Group 2
allowances in the new unit set-aside for
the State for such control period is less
than the sum under paragraph (a)(5) of
this section, then the Administrator will
allocate to each such TR SO2 Group 2
unit the amount of the TR SO2 Group 2
allowances determined under paragraph
(a)(4)(i) of this section for the unit,
multiplied by the amount of TR SO2
Group 2 allowances in the new unit setaside for such control period, divided
by the sum under paragraph (a)(5) of
this section, and rounded to the nearest
allowance.
(8) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.711(b)(1)(i) and (ii), of the amount
of TR SO2 Group 2 allowances allocated
under paragraphs (a)(2) through (7) and
(12) of this section for such control
period to each TR SO2 Group 2 unit
eligible for such allocation.
(9) If, after completion of the
procedures under paragraphs (a)(5)
through (8) of this section for such
control period, any unallocated TR SO2
Group 2 allowances remain in the new
unit set-aside for the State for such
control period, the Administrator will
allocate such TR SO2 Group 2
allowances as follows—
(i) The Administrator will determine,
for each unit described in paragraph
(a)(1) of this section that commenced
commercial operation during the period
starting January 1 of the year before the
year of such control period and ending
November 30 of year of such control
period, the positive difference (if any)
between the unit’s emissions during
such control period and the amount of
TR SO2 Group 2 allowances referenced
in the notice of data availability
required under § 97.711(b)(1)(ii) for the
unit for such control period;
(ii) The Administrator will determine
the sum of the positive differences
determined under paragraph (a)(9)(i) of
this section;
(iii) If the amount of unallocated TR
SO2 Group 2 allowances remaining in
the new unit set-aside for the State for
such control period is greater than or
equal to the sum determined under
paragraph (a)(9)(ii) of this section, then
the Administrator will allocate the
amount of TR SO2 Group 2 allowances
determined for each such TR SO2 Group
2 unit under paragraph (a)(9)(i) of this
section; and
(iv) If the amount of unallocated TR
SO2 Group 2 allowances remaining in
the new unit set-aside for the State for
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Sfmt 4700
48469
such control period is less than the sum
under paragraph (a)(9)(ii) of this section,
then the Administrator will allocate to
each such TR SO2 Group 2 unit the
amount of the TR SO2 Group 2
allowances determined under paragraph
(a)(9)(i) of this section for the unit,
multiplied by the amount of unallocated
TR SO2 Group 2 allowances remaining
in the new unit set-aside for such
control period, divided by the sum
under paragraph (a)(9)(ii) of this section,
and rounded to the nearest allowance.
(10) If, after completion of the
procedures under paragraphs (a)(9) and
(12) of this section for such control
period, any unallocated TR SO2 Group
2 allowances remain in the new unit setaside for the State for such control
period, the Administrator will allocate
to each TR SO2 Group 2 unit that is in
the State, is allocated an amount of TR
SO2 Group 2 allowances in the notice of
data availability issued under
§ 97.711(a)(1), and continues to be
allocated TR SO2 Group 2 allowances
for such control period in accordance
with § 97.711(a)(2), an amount of TR
SO2 Group 2 allowances equal to the
following: The total amount of such
remaining unallocated TR SO2 Group 2
allowances in such new unit set-aside,
multiplied by the unit’s allocation
under § 97.711(a) for such control
period, divided by the remainder of the
amount of tons in the applicable State
SO2 Group 2 trading budget minus the
sum of the amounts of tons in such new
unit set-aside and the Indian country
new unit set-aside for the State for such
control period, and rounded to the
nearest allowance.
(11) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.711(b)(1)(iii), (iv), and (v), of the
amount of TR SO2 Group 2 allowances
allocated under paragraphs (a)(9), (10),
and (12) of this section for such control
period to each TR SO2 Group 2 unit
eligible for such allocation.
(12)(i) Notwithstanding the
requirements of paragraphs (a)(2)
through (11) of this section, if the
calculations of allocations of a new unit
set-aside for a control period in a given
year under paragraph (a)(7) of this
section, paragraphs (a)(6) and (9)(iv) of
this section, or paragraphs (a)(6), (9)(iii),
and (10) of this section would otherwise
result in total allocations of such new
unit set-aside exceeding the total
amount of such new unit set-aside, then
the Administrator will adjust the results
of the calculations under paragraph
(a)(7), (9)(iv), or (10) of this section, as
applicable, as follows. The
Administrator will list the TR SO2
Group 2 units in descending order based
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on the amount of such units’ allocations
under paragraph (a)(7), (9)(iv), or (10) of
this section, as applicable, and, in cases
of equal allocation amounts, in
alphabetical order of the relevant
source’s name and numerical order of
the relevant unit’s identification
number, and will reduce each unit’s
allocation under paragraph (a)(7),
(9)(iv), or (10) of this section, as
applicable, by one TR SO2 Group 2
allowance (but not below zero) in the
order in which the units are listed and
will repeat this reduction process as
necessary, until the total allocations of
such new unit set-aside equal the total
amount of such new unit set-aside.
(ii) Notwithstanding the requirements
of paragraphs (a)(10) and (11) of this
section, if the calculations of allocations
of a new unit set-aside for a control
period in a given year under paragraphs
(a)(6), (9)(iii), and (10) of this section
would otherwise result in a total
allocations of such new unit set-aside
less than the total amount of such new
unit set-aside, then the Administrator
will adjust the results of the calculations
under paragraph (a)(10) of this section,
as follows. The Administrator will list
the TR SO2 Group 2 units in descending
order based on the amount of such
units’ allocations under paragraph
(a)(10) of this section and, in cases of
equal allocation amounts, in
alphabetical order of the relevant
source’s name and numerical order of
the relevant unit’s identification
number, and will increase each unit’s
allocation under paragraph (a)(10) of
this section by one TR SO2 Group 2
allowance in the order in which the
units are listed and will repeat this
increase process as necessary, until the
total allocations of such new unit setaside equal the total amount of such
new unit set-aside.
(b) For each control period in 2012
and thereafter and for the TR SO2 Group
2 units located in Indian country within
the borders of each State, the
Administrator will allocate TR SO2
Group 2 allowances to the TR SO2
Group 2 units as follows:
(1) The TR SO2 Group 2 allowances
will be allocated to the following TR
SO2 Group 2 units, except as provided
in paragraph (b)(10) of this section:
(i) TR SO2 Group 2 units that are not
allocated an amount of TR SO2 Group 2
allowances in the notice of data
availability issued under § 97.711(a)(1);
or
(ii) For purposes of paragraph (b)(9) of
this section, TR SO2 Group 2 units
under § 97.711(c)(1)(ii) whose allocation
of an amount of TR SO2 Group 2
allowances for such control period in
the notice of data availability issued
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Jkt 223001
under § 97.711(b)(2)(ii)(B) is covered by
§ 97.711(c)(2) or (3).
(2) The Administrator will establish a
separate Indian country new unit setaside for the State for each such control
period. Each such Indian country new
unit set-aside will be allocated TR SO2
Group 2 allowances in an amount equal
to the applicable amount of tons of SO2
emissions as set forth in § 97.710(a) and
will be allocated additional TR SO2
Group 2 allowances (if any) in
accordance with § 97.711(c)(5).
(3) The Administrator will determine,
for each TR SO2 Group 2 unit described
in paragraph (b)(1) of this section, an
allocation of TR SO2 Group 2
allowances for the later of the following
control periods and for each subsequent
control period:
(i) The control period in 2012; and
(ii) The first control period after the
control period in which the TR SO2
Group 2 unit commences commercial
operation.
(4)(i) The allocation to each TR SO2
annual unit described in paragraph
(b)(1)(i) of this section and for each
control period described in paragraph
(b)(3) of this section will be an amount
equal to the unit’s total tons of SO2
emissions during the immediately
preceding control period.
(ii) The Administrator will adjust the
allocation amount in paragraph (b)(4)(i)
in accordance with paragraphs (b)(5)
through (7) and (12) of this section.
(5) The Administrator will calculate
the sum of the TR SO2 Group 2
allowances determined for all such TR
SO2 Group 2 units under paragraph
(b)(4)(i) of this section in Indian country
within the borders of the State for such
control period.
(6) If the amount of TR SO2 Group 2
allowances in the Indian country new
unit set-aside for the State for such
control period is greater than or equal to
the sum under paragraph (b)(5) of this
section, then the Administrator will
allocate the amount of TR SO2 Group 2
allowances determined for each such TR
SO2 Group 2 unit under paragraph
(b)(4)(i) of this section.
(7) If the amount of TR SO2 Group 2
allowances in the Indian country new
unit set-aside for the State for such
control period is less than the sum
under paragraph (b)(5) of this section,
then the Administrator will allocate to
each such TR SO2 Group 2 unit the
amount of the TR SO2 Group 2
allowances determined under paragraph
(b)(4)(i) of this section for the unit,
multiplied by the amount of TR SO2
Group 2 allowances in the Indian
country new unit set-aside for such
control period, divided by the sum
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under paragraph (b)(5) of this section,
and rounded to the nearest allowance.
(8) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.711(b)(2)(i) and (ii), of the amount
of TR SO2 Group 2 allowances allocated
under paragraphs (b)(2) through (7) and
(12) of this section for such control
period to each TR SO2 Group 2 unit
eligible for such allocation.
(9) If, after completion of the
procedures under paragraphs (b)(5)
through (8) of this section for such
control period, any unallocated TR SO2
Group 2 allowances remain in the
Indian country new unit set-aside for
the State for such control period, the
Administrator will allocate such TR SO2
Group 2 allowances as follows—
(i) The Administrator will determine,
for each unit described in paragraph
(b)(1) of this section that commenced
commercial operation during the period
starting January 1 of the year before the
year of such control period and ending
November 30 of year of such control
period, the positive difference (if any)
between the unit’s emissions during
such control period and the amount of
TR SO2 Group 2 allowances referenced
in the notice of data availability
required under § 97.711(b)(2)(ii) for the
unit for such control period;
(ii) The Administrator will determine
the sum of the positive differences
determined under paragraph (b)(9)(i) of
this section;
(iii) If the amount of unallocated TR
SO2 Group 2 allowances remaining in
the Indian country new unit set-aside
for the State for such control period is
greater than or equal to the sum
determined under paragraph (b)(9)(ii) of
this section, then the Administrator will
allocate the amount of TR SO2 Group 2
allowances determined for each such TR
SO2 Group 2 unit under paragraph
(b)(9)(i) of this section; and
(iv) If the amount of unallocated TR
SO2 Group 2 allowances remaining in
the Indian country new unit set-aside
for the State for such control period is
less than the sum under paragraph
(b)(9)(ii) of this section, then the
Administrator will allocate to each such
TR SO2 Group 2 unit the amount of the
TR SO2 Group 2 allowances determined
under paragraph (b)(9)(i) of this section
for the unit, multiplied by the amount
of unallocated TR SO2 Group 2
allowances remaining in the Indian
country new unit set-aside for such
control period, divided by the sum
under paragraph (b)(9)(ii) of this section,
and rounded to the nearest allowance.
(10) If, after completion of the
procedures under paragraphs (b)(9) and
(12) of this section for such control
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period, any unallocated TR SO2 Group
2 allowances remain in the Indian
country new unit set-aside for the State
for such control period, the
Administrator will:
(i) Transfer such unallocated TR SO2
Group 2 allowances to the new unit setaside for the State for such control
period; or
(ii) If the State has a SIP revision
approved under § 52.39(g), (h), or (i) of
this chapter covering such control
period, include such unallocated TR
SO2 Group 2 allowances in the portion
of the State SO2 Group 2 trading budget
that may be allocated for such control
period in accordance with such SIP
revision.
(11) The Administrator will notify the
public, through the promulgation of the
notices of data availability described in
§ 97.711(b)(2)(iii), (iv), and (v), of the
amount of TR SO2 Group 2 allowances
allocated under paragraphs (b)(9), (10),
and (12) of this section for such control
period to each TR SO2 Group 2 unit
eligible for such allocation.
(12)(i) Notwithstanding the
requirements of paragraphs (b)(2)
through (11) of this section, if the
calculations of allocations of an Indian
country new unit set-aside for a control
period in a given year under paragraph
(b)(7) of this section, paragraphs (b)(6)
and (9)(iv) of this section, or paragraphs
(b)(6), (9)(iii), and (10) of this section
would otherwise result in total
allocations of such Indian country new
unit set-aside exceeding the total
amount of such Indian country new unit
set-aside, then the Administrator will
adjust the results of the calculations
under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, as follows.
The Administrator will list the TR SO2
Group 2 units in descending order based
on the amount of such units’ allocations
under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, and, in cases
of equal allocation amounts, in
alphabetical order of the relevant
source’s name and numerical order of
the relevant unit’s identification
number, and will reduce each unit’s
allocation under paragraph (b)(7),
(9)(iv), or (10) of this section, as
applicable, by one TR SO2 Group 2
allowance (but not below zero) in the
order in which the units are listed and
will repeat this reduction process as
necessary, until the total allocations of
such Indian country new unit set-aside
equal the total amount of such Indian
country new unit set-aside.
(ii) Notwithstanding the requirements
of paragraphs (b)(10) and (11) of this
section, if the calculations of allocations
of an Indian country new unit set-aside
for a control period in a given year
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under paragraphs (b)(6), (9)(iii), and (10)
of this section would otherwise result in
a total allocations of such Indian
country new unit set-aside less than the
total amount of such Indian country
new unit set-aside, then the
Administrator will adjust the results of
the calculations under paragraph (b)(10)
of this section, as follows. The
Administrator will list the TR SO2
Group 2 units in descending order based
on the amount of such units’ allocations
under paragraph (b)(10) of this section
and, in cases of equal allocation
amounts, in alphabetical order of the
relevant source’s name and numerical
order of the relevant unit’s
identification number, and will increase
each unit’s allocation under paragraph
(b)(10) of this section by one TR SO2
Group 2 allowance in the order in
which the units are listed and will
repeat this increase process as
necessary, until the total allocations of
such Indian country new unit set-aside
equal the total amount of such Indian
country new unit set-aside.
§ 97.713 Authorization of designated
representative and alternate designated
representative.
(a) Except as provided under § 97.715,
each TR SO2 Group 2 source, including
all TR SO2 Group 2 units at the source,
shall have one and only one designated
representative, with regard to all matters
under the TR SO2 Group 2 Trading
Program.
(1) The designated representative
shall be selected by an agreement
binding on the owners and operators of
the source and all TR SO2 Group 2 units
at the source and shall act in accordance
with the certification statement in
§ 97.716(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 97.716:
(i) The designated representative shall
be authorized and shall represent and,
by his or her representations, actions,
inactions, or submissions, legally bind
each owner and operator of the source
and each TR SO2 Group 2 unit at the
source in all matters pertaining to the
TR SO2 Group 2 Trading Program,
notwithstanding any agreement between
the designated representative and such
owners and operators; and
(ii) The owners and operators of the
source and each TR SO2 Group 2 unit
at the source shall be bound by any
decision or order issued to the
designated representative by the
Administrator regarding the source or
any such unit.
(b) Except as provided under § 97.715,
each TR SO2 Group 2 source may have
one and only one alternate designated
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representative, who may act on behalf of
the designated representative. The
agreement by which the alternate
designated representative is selected
shall include a procedure for
authorizing the alternate designated
representative to act in lieu of the
designated representative.
(1) The alternate designated
representative shall be selected by an
agreement binding on the owners and
operators of the source and all TR SO2
Group 2 units at the source and shall act
in accordance with the certification
statement in § 97.716(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 97.716,
(i) The alternate designated
representative shall be authorized;
(ii) Any representation, action,
inaction, or submission by the alternate
designated representative shall be
deemed to be a representation, action,
inaction, or submission by the
designated representative; and
(iii) The owners and operators of the
source and each TR SO2 Group 2 unit
at the source shall be bound by any
decision or order issued to the alternate
designated representative by the
Administrator regarding the source or
any such unit.
(c) Except in this section, § 97.702,
and §§ 97.714 through 97.718, whenever
the term ‘‘designated representative’’ (as
distinguished from the term ‘‘common
designated representative’’) is used in
this subpart, the term shall be construed
to include the designated representative
or any alternate designated
representative.
§ 97.714 Responsibilities of designated
representative and alternate designated
representative.
(a) Except as provided under § 97.718
concerning delegation of authority to
make submissions, each submission
under the TR SO2 Group 2 Trading
Program shall be made, signed, and
certified by the designated
representative or alternate designated
representative for each TR SO2 Group 2
source and TR SO2 Group 2 unit for
which the submission is made. Each
such submission shall include the
following certification statement by the
designated representative or alternate
designated representative: ‘‘I am
authorized to make this submission on
behalf of the owners and operators of
the source or units for which the
submission is made. I certify under
penalty of law that I have personally
examined, and am familiar with, the
statements and information submitted
in this document and all its
attachments. Based on my inquiry of
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those individuals with primary
responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(b) The Administrator will accept or
act on a submission made for a TR SO2
Group 2 source or a TR SO2 Group 2
unit only if the submission has been
made, signed, and certified in
accordance with paragraph (a) of this
section and § 97.718.
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§ 97.715 Changing designated
representative and alternate designated
representative; changes in owners and
operators; changes in units at the source.
(a) Changing designated
representative. The designated
representative may be changed at any
time upon receipt by the Administrator
of a superseding complete certificate of
representation under § 97.716.
Notwithstanding any such change, all
representations, actions, inactions, and
submissions by the previous designated
representative before the time and date
when the Administrator receives the
superseding certificate of representation
shall be binding on the new designated
representative and the owners and
operators of the TR SO2 Group 2 source
and the TR SO2 Group 2 units at the
source.
(b) Changing alternate designated
representative. The alternate designated
representative may be changed at any
time upon receipt by the Administrator
of a superseding complete certificate of
representation under § 97.716.
Notwithstanding any such change, all
representations, actions, inactions, and
submissions by the previous alternate
designated representative before the
time and date when the Administrator
receives the superseding certificate of
representation shall be binding on the
new alternate designated representative,
the designated representative, and the
owners and operators of the TR SO2
Group 2 source and the TR SO2 Group
2 units at the source.
(c) Changes in owners and operators.
(1) In the event an owner or operator of
a TR SO2 Group 2 source or a TR SO2
Group 2 unit at the source is not
included in the list of owners and
operators in the certificate of
representation under § 97.716, such
owner or operator shall be deemed to be
subject to and bound by the certificate
of representation, the representations,
actions, inactions, and submissions of
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the designated representative and any
alternate designated representative of
the source or unit, and the decisions
and orders of the Administrator, as if
the owner or operator were included in
such list.
(2) Within 30 days after any change in
the owners and operators of a TR SO2
Group 2 source or a TR SO2 Group 2
unit at the source, including the
addition or removal of an owner or
operator, the designated representative
or any alternate designated
representative shall submit a revision to
the certificate of representation under
§ 97.716 amending the list of owners
and operators to reflect the change.
(d) Changes in units at the source.
Within 30 days of any change in which
units are located at a TR SO2 Group 2
source (including the addition or
removal of a unit), the designated
representative or any alternate
designated representative shall submit a
certificate of representation under
§ 97.716 amending the list of units to
reflect the change.
(1) If the change is the addition of a
unit that operated (other than for
purposes of testing by the manufacturer
before initial installation) before being
located at the source, then the certificate
of representation shall identify, in a
format prescribed by the Administrator,
the entity from whom the unit was
purchased or otherwise obtained
(including name, address, telephone
number, and facsimile number (if any)),
the date on which the unit was
purchased or otherwise obtained, and
the date on which the unit became
located at the source.
(2) If the change is the removal of a
unit, then the certificate of
representation shall identify, in a format
prescribed by the Administrator, the
entity to which the unit was sold or that
otherwise obtained the unit (including
name, address, telephone number, and
facsimile number (if any)), the date on
which the unit was sold or otherwise
obtained, and the date on which the
unit became no longer located at the
source.
§ 97.716
Certificate of representation.
(a) A complete certificate of
representation for a designated
representative or an alternate designated
representative shall include the
following elements in a format
prescribed by the Administrator:
(1) Identification of the TR SO2 Group
2 source, and each TR SO2 Group 2 unit
at the source, for which the certificate
of representation is submitted,
including source name, source category
and NAICS code (or, in the absence of
a NAICS code, an equivalent code),
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State, plant code, county, latitude and
longitude, unit identification number
and type, identification number and
nameplate capacity (in MWe, rounded
to the nearest tenth) of each generator
served by each such unit, actual or
projected date of commencement of
commercial operation, and a statement
of whether such source is located in
Indian Country. If a projected date of
commencement of commercial
operation is provided, the actual date of
commencement of commercial
operation shall be provided when such
information becomes available.
(2) The name, address, e-mail address
(if any), telephone number, and
facsimile transmission number (if any)
of the designated representative and any
alternate designated representative.
(3) A list of the owners and operators
of the TR SO2 Group 2 source and of
each TR SO2 Group 2 unit at the source.
(4) The following certification
statements by the designated
representative and any alternate
designated representative—
(i) ‘‘I certify that I was selected as the
designated representative or alternate
designated representative, as applicable,
by an agreement binding on the owners
and operators of the source and each TR
SO2 Group 2 unit at the source.’’
(ii) ‘‘I certify that I have all the
necessary authority to carry out my
duties and responsibilities under the TR
SO2 Group 2 Trading Program on behalf
of the owners and operators of the
source and of each TR SO2 Group 2 unit
at the source and that each such owner
and operator shall be fully bound by my
representations, actions, inactions, or
submissions and by any decision or
order issued to me by the Administrator
regarding the source or unit.’’
(iii) ‘‘Where there are multiple
holders of a legal or equitable title to, or
a leasehold interest in, a TR SO2 Group
2 unit, or where a utility or industrial
customer purchases power from a TR
SO2 Group 2 unit under a life-of-theunit, firm power contractual
arrangement, I certify that: I have given
a written notice of my selection as the
‘designated representative’ or ‘alternate
designated representative’, as
applicable, and of the agreement by
which I was selected to each owner and
operator of the source and of each TR
SO2 Group 2 unit at the source; and TR
SO2 Group 2 allowances and proceeds
of transactions involving TR SO2 Group
2 allowances will be deemed to be held
or distributed in proportion to each
holder’s legal, equitable, leasehold, or
contractual reservation or entitlement,
except that, if such multiple holders
have expressly provided for a different
distribution of TR SO2 Group 2
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allowances by contract, TR SO2 Group
2 allowances and proceeds of
transactions involving TR SO2 Group 2
allowances will be deemed to be held or
distributed in accordance with the
contract.’’
(5) The signature of the designated
representative and any alternate
designated representative and the dates
signed.
(b) Unless otherwise required by the
Administrator, documents of agreement
referred to in the certificate of
representation shall not be submitted to
the Administrator. The Administrator
shall not be under any obligation to
review or evaluate the sufficiency of
such documents, if submitted.
§ 97.717 Objections concerning
designated representative and alternate
designated representative.
(a) Once a complete certificate of
representation under § 97.716 has been
submitted and received, the
Administrator will rely on the certificate
of representation unless and until a
superseding complete certificate of
representation under § 97.716 is
received by the Administrator.
(b) Except as provided in paragraph
(a) of this section, no objection or other
communication submitted to the
Administrator concerning the
authorization, or any representation,
action, inaction, or submission, of a
designated representative or alternate
designated representative shall affect
any representation, action, inaction, or
submission of the designated
representative or alternate designated
representative or the finality of any
decision or order by the Administrator
under the TR SO2 Group 2 Trading
Program.
(c) The Administrator will not
adjudicate any private legal dispute
concerning the authorization or any
representation, action, inaction, or
submission of any designated
representative or alternate designated
representative, including private legal
disputes concerning the proceeds of TR
SO2 Group 2 allowance transfers.
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§ 97.718 Delegation by designated
representative and alternate designated
representative.
(a) A designated representative may
delegate, to one or more natural persons,
his or her authority to make an
electronic submission to the
Administrator provided for or required
under this subpart.
(b) An alternate designated
representative may delegate, to one or
more natural persons, his or her
authority to make an electronic
submission to the Administrator
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provided for or required under this
subpart.
(c) In order to delegate authority to a
natural person to make an electronic
submission to the Administrator in
accordance with paragraph (a) or (b) of
this section, the designated
representative or alternate designated
representative, as appropriate, must
submit to the Administrator a notice of
delegation, in a format prescribed by the
Administrator, that includes the
following elements:
(1) The name, address, e-mail address,
telephone number, and facsimile
transmission number (if any) of such
designated representative or alternate
designated representative;
(2) The name, address, e-mail address,
telephone number, and facsimile
transmission number (if any) of each
such natural person (referred to in this
section as an ‘‘agent’’);
(3) For each such natural person, a list
of the type or types of electronic
submissions under paragraph (a) or (b)
of this section for which authority is
delegated to him or her; and
(4) The following certification
statements by such designated
representative or alternate designated
representative:
(i) ‘‘I agree that any electronic
submission to the Administrator that is
made by an agent identified in this
notice of delegation and of a type listed
for such agent in this notice of
delegation and that is made when I am
a designated representative or alternate
designated representative, as
appropriate, and before this notice of
delegation is superseded by another
notice of delegation under 40 CFR
97.718(d) shall be deemed to be an
electronic submission by me.’’
(ii) ‘‘Until this notice of delegation is
superseded by another notice of
delegation under 40 CFR 97.718(d), I
agree to maintain an e-mail account and
to notify the Administrator immediately
of any change in my e-mail address
unless all delegation of authority by me
under 40 CFR 97.718 is terminated.’’.
(d) A notice of delegation submitted
under paragraph (c) of this section shall
be effective, with regard to the
designated representative or alternate
designated representative identified in
such notice, upon receipt of such notice
by the Administrator and until receipt
by the Administrator of a superseding
notice of delegation submitted by such
designated representative or alternate
designated representative, as
appropriate. The superseding notice of
delegation may replace any previously
identified agent, add a new agent, or
eliminate entirely any delegation of
authority.
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48473
(e) Any electronic submission covered
by the certification in paragraph (c)(4)(i)
of this section and made in accordance
with a notice of delegation effective
under paragraph (d) of this section shall
be deemed to be an electronic
submission by the designated
representative or alternate designated
representative submitting such notice of
delegation.
§ 97.719
[Reserved]
§ 97.720 Establishment of compliance
accounts, assurance accounts, and general
accounts.
(a) Compliance accounts. Upon
receipt of a complete certificate of
representation under § 97.716, the
Administrator will establish a
compliance account for the TR SO2
Group 2 source for which the certificate
of representation was submitted, unless
the source already has a compliance
account. The designated representative
and any alternate designated
representative of the source shall be the
authorized account representative and
the alternate authorized account
representative respectively of the
compliance account.
(b) Assurance accounts. The
Administrator will establish assurance
accounts for certain owners and
operators and States in accordance with
§ 97.725(b)(3).
(c) General accounts. (1) Application
for general account. (i) Any person may
apply to open a general account, for the
purpose of holding and transferring TR
SO2 Group 2 allowances, by submitting
to the Administrator a complete
application for a general account. Such
application shall designate one and only
one authorized account representative
and may designate one and only one
alternate authorized account
representative who may act on behalf of
the authorized account representative.
(A) The authorized account
representative and alternate authorized
account representative shall be selected
by an agreement binding on the persons
who have an ownership interest with
respect to TR SO2 Group 2 allowances
held in the general account.
(B) The agreement by which the
alternate authorized account
representative is selected shall include
a procedure for authorizing the alternate
authorized account representative to act
in lieu of the authorized account
representative.
(ii) A complete application for a
general account shall include the
following elements in a format
prescribed by the Administrator:
(A) Name, mailing address, e-mail
address (if any), telephone number, and
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facsimile transmission number (if any)
of the authorized account representative
and any alternate authorized account
representative;
(B) An identifying name for the
general account;
(C) A list of all persons subject to a
binding agreement for the authorized
account representative and any alternate
authorized account representative to
represent their ownership interest with
respect to the TR SO2 Group 2
allowances held in the general account;
(D) The following certification
statement by the authorized account
representative and any alternate
authorized account representative: ‘‘I
certify that I was selected as the
authorized account representative or the
alternate authorized account
representative, as applicable, by an
agreement that is binding on all persons
who have an ownership interest with
respect to TR SO2 Group 2 allowances
held in the general account. I certify that
I have all the necessary authority to
carry out my duties and responsibilities
under the TR SO2 Group 2 Trading
Program on behalf of such persons and
that each such person shall be fully
bound by my representations, actions,
inactions, or submissions and by any
decision or order issued to me by the
Administrator regarding the general
account.’’
(E) The signature of the authorized
account representative and any alternate
authorized account representative and
the dates signed.
(iii) Unless otherwise required by the
Administrator, documents of agreement
referred to in the application for a
general account shall not be submitted
to the Administrator. The Administrator
shall not be under any obligation to
review or evaluate the sufficiency of
such documents, if submitted.
(2) Authorization of authorized
account representative and alternate
authorized account representative. (i)
Upon receipt by the Administrator of a
complete application for a general
account under paragraph (b)(1) of this
section, the Administrator will establish
a general account for the person or
persons for whom the application is
submitted, and upon and after such
receipt by the Administrator:
(A) The authorized account
representative of the general account
shall be authorized and shall represent
and, by his or her representations,
actions, inactions, or submissions,
legally bind each person who has an
ownership interest with respect to TR
SO2 Group 2 allowances held in the
general account in all matters pertaining
to the TR SO2 Group 2 Trading Program,
notwithstanding any agreement between
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the authorized account representative
and such person.
(B) Any alternate authorized account
representative shall be authorized, and
any representation, action, inaction, or
submission by any alternate authorized
account representative shall be deemed
to be a representation, action, inaction,
or submission by the authorized account
representative.
(C) Each person who has an
ownership interest with respect to TR
SO2 Group 2 allowances held in the
general account shall be bound by any
decision or order issued to the
authorized account representative or
alternate authorized account
representative by the Administrator
regarding the general account.
(ii) Except as provided in paragraph
(c)(5) of this section concerning
delegation of authority to make
submissions, each submission
concerning the general account shall be
made, signed, and certified by the
authorized account representative or
any alternate authorized account
representative for the persons having an
ownership interest with respect to TR
SO2 Group 2 allowances held in the
general account. Each such submission
shall include the following certification
statement by the authorized account
representative or any alternate
authorized account representative: ‘‘I
am authorized to make this submission
on behalf of the persons having an
ownership interest with respect to the
TR SO2 Group 2 allowances held in the
general account. I certify under penalty
of law that I have personally examined,
and am familiar with, the statements
and information submitted in this
document and all its attachments. Based
on my inquiry of those individuals with
primary responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(iii) Except in this section, whenever
the term ‘‘authorized account
representative’’ is used in this subpart,
the term shall be construed to include
the authorized account representative or
any alternate authorized account
representative.
(3) Changing authorized account
representative and alternate authorized
account representative; changes in
persons with ownership interest. (i) The
authorized account representative of a
general account may be changed at any
time upon receipt by the Administrator
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of a superseding complete application
for a general account under paragraph
(c)(1) of this section. Notwithstanding
any such change, all representations,
actions, inactions, and submissions by
the previous authorized account
representative before the time and date
when the Administrator receives the
superseding application for a general
account shall be binding on the new
authorized account representative and
the persons with an ownership interest
with respect to the TR SO2 Group 2
allowances in the general account.
(ii) The alternate authorized account
representative of a general account may
be changed at any time upon receipt by
the Administrator of a superseding
complete application for a general
account under paragraph (c)(1) of this
section. Notwithstanding any such
change, all representations, actions,
inactions, and submissions by the
previous alternate authorized account
representative before the time and date
when the Administrator receives the
superseding application for a general
account shall be binding on the new
alternate authorized account
representative, the authorized account
representative, and the persons with an
ownership interest with respect to the
TR SO2 Group 2 allowances in the
general account.
(iii)(A) In the event a person having
an ownership interest with respect to
TR SO2 Group 2 allowances in the
general account is not included in the
list of such persons in the application
for a general account, such person shall
be deemed to be subject to and bound
by the application for a general account,
the representation, actions, inactions,
and submissions of the authorized
account representative and any alternate
authorized account representative of the
account, and the decisions and orders of
the Administrator, as if the person were
included in such list.
(B) Within 30 days after any change
in the persons having an ownership
interest with respect to SO2 Group 2
allowances in the general account,
including the addition or removal of a
person, the authorized account
representative or any alternate
authorized account representative shall
submit a revision to the application for
a general account amending the list of
persons having an ownership interest
with respect to the TR SO2 Group 2
allowances in the general account to
include the change.
(4) Objections concerning authorized
account representative and alternate
authorized account representative. (i)
Once a complete application for a
general account under paragraph (c)(1)
of this section has been submitted and
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received, the Administrator will rely on
the application unless and until a
superseding complete application for a
general account under paragraph (b)(1)
of this section is received by the
Administrator.
(ii) Except as provided in paragraph
(c)(4)(i) of this section, no objection or
other communication submitted to the
Administrator concerning the
authorization, or any representation,
action, inaction, or submission of the
authorized account representative or
any alternate authorized account
representative of a general account shall
affect any representation, action,
inaction, or submission of the
authorized account representative or
any alternate authorized account
representative or the finality of any
decision or order by the Administrator
under the TR SO2 Group 2 Trading
Program.
(iii) The Administrator will not
adjudicate any private legal dispute
concerning the authorization or any
representation, action, inaction, or
submission of the authorized account
representative or any alternate
authorized account representative of a
general account, including private legal
disputes concerning the proceeds of TR
SO2 Group 2 allowance transfers.
(5) Delegation by authorized account
representative and alternate authorized
account representative. (i) An
authorized account representative of a
general account may delegate, to one or
more natural persons, his or her
authority to make an electronic
submission to the Administrator
provided for or required under this
subpart.
(ii) An alternate authorized account
representative of a general account may
delegate, to one or more natural persons,
his or her authority to make an
electronic submission to the
Administrator provided for or required
under this subpart.
(iii) In order to delegate authority to
a natural person to make an electronic
submission to the Administrator in
accordance with paragraph (c)(5)(i) or
(ii) of this section, the authorized
account representative or alternate
authorized account representative, as
appropriate, must submit to the
Administrator a notice of delegation, in
a format prescribed by the
Administrator, that includes the
following elements:
(A) The name, address, e-mail
address, telephone number, and
facsimile transmission number (if any)
of such authorized account
representative or alternate authorized
account representative;
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(B) The name, address, e-mail
address, telephone number, and
facsimile transmission number (if any)
of each such natural person (referred to
in this section as an ‘‘agent’’);
(C) For each such natural person, a
list of the type or types of electronic
submissions under paragraph (c)(5)(i) or
(ii) of this section for which authority is
delegated to him or her;
(D) The following certification
statement by such authorized account
representative or alternate authorized
account representative: ‘‘I agree that any
electronic submission to the
Administrator that is made by an agent
identified in this notice of delegation
and of a type listed for such agent in
this notice of delegation and that is
made when I am an authorized account
representative or alternate authorized
representative, as appropriate, and
before this notice of delegation is
superseded by another notice of
delegation under 40 CFR 97.720(c)(5)(iv)
shall be deemed to be an electronic
submission by me.’’; and
(E) The following certification
statement by such authorized account
representative or alternate authorized
account representative: ‘‘Until this
notice of delegation is superseded by
another notice of delegation under 40
CFR 97.720(c)(5)(iv), I agree to maintain
an e-mail account and to notify the
Administrator immediately of any
change in my e-mail address unless all
delegation of authority by me under 40
CFR 97.720(c)(5) is terminated.’’.
(iv) A notice of delegation submitted
under paragraph (c)(5)(iii) of this section
shall be effective, with regard to the
authorized account representative or
alternate authorized account
representative identified in such notice,
upon receipt of such notice by the
Administrator and until receipt by the
Administrator of a superseding notice of
delegation submitted by such
authorized account representative or
alternate authorized account
representative, as appropriate. The
superseding notice of delegation may
replace any previously identified agent,
add a new agent, or eliminate entirely
any delegation of authority.
(v) Any electronic submission covered
by the certification in paragraph
(c)(5)(iii)(D) of this section and made in
accordance with a notice of delegation
effective under paragraph (c)(5)(iv) of
this section shall be deemed to be an
electronic submission by the designated
representative or alternate designated
representative submitting such notice of
delegation.
(6) Closing a general account. (i) The
authorized account representative or
alternate authorized account
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48475
representative of a general account may
submit to the Administrator a request to
close the account. Such request shall
include a correctly submitted TR SO2
Group 2 allowance transfer under
§ 97.722 for any TR SO2 Group 2
allowances in the account to one or
more other Allowance Management
System accounts.
(ii) If a general account has no TR SO2
Group 2 allowance transfers to or from
the account for a 12-month period or
longer and does not contain any TR SO2
Group 2 allowances, the Administrator
may notify the authorized account
representative for the account that the
account will be closed after 30 days
after the notice is sent. The account will
be closed after the 30-day period unless,
before the end of the 30-day period, the
Administrator receives a correctly
submitted TR SO2 Group 2 allowance
transfer under § 97.722 to the account or
a statement submitted by the authorized
account representative or alternate
authorized account representative
demonstrating to the satisfaction of the
Administrator good cause as to why the
account should not be closed.
(d) Account identification. The
Administrator will assign a unique
identifying number to each account
established under paragraph (a), (b), or
(c) of this section.
(e) Responsibilities of authorized
account representative and alternate
authorized account representative. After
the establishment of a compliance
account or general account, the
Administrator will accept or act on a
submission pertaining to the account,
including, but not limited to,
submissions concerning the deduction
or transfer of TR SO2 Group 2
allowances in the account, only if the
submission has been made, signed, and
certified in accordance with §§ 97.714(a)
and 97.718 or paragraphs (c)(2)(ii) and
(c)(5) of this section.
§ 97.721 Recordation of TR SO2 Group 2
allowance allocations and auction results.
(a) By November 7, 2011, the
Administrator will record in each TR
SO2 Group 2 source’s compliance
account the TR SO2 Group 2 allowances
allocated to the TR SO2 Group 2 units
at the source in accordance with
§ 97.711(a) for the control period in
2012.
(b) By November 7, 2011, the
Administrator will record in each TR
SO2 Group 2 source’s compliance
account the TR SO2 Group 2 allowances
allocated to the TR SO2 Group 2 units
at the source in accordance with
§ 97.711(a) for the control period in
2013, unless the State in which the
source is located notifies the
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
Administrator in writing by October 17,
2011 of the State’s intent to submit to
the Administrator a complete SIP
revision by April 1, 2012 meeting the
requirements of § 52.39(g)(1) through (4)
of this chapter.
(1) If, by April 1, 2012, the State does
not submit to the Administrator such
complete SIP revision, the
Administrator will record by April 15,
2012 in each TR SO2 Group 2 source’s
compliance account the TR SO2 Group
2 allowances allocated to the TR SO2
Group 2 units at the source in
accordance with § 97.711(a) for the
control period in 2013.
(2) If the State submits to the
Administrator by April 1, 2012, and the
Administrator approves by October 1,
2012, such complete SIP revision, the
Administrator will record by October 1,
2012 in each TR SO2 Group 2 source’s
compliance account the TR SO2 Group
2 allowances allocated to the TR SO2
Group 2 units at the source as provided
in such approved, complete SIP revision
for the control period in 2013.
(3) If the State submits to the
Administrator by April 1, 2012, and the
Administrator does not approve by
October 1, 2012, such complete SIP
revision, the Administrator will record
by October 1, 2012 in each TR SO2
Group 2 source’s compliance account
the TR SO2 Group 2 allowances
allocated to the TR SO2 Group 2 units
at the source in accordance with
§ 97.711(a) for the control period in
2013.
(c) By July 1, 2013, the Administrator
will record in each TR SO2 Group 2
source’s compliance account the TR SO2
Group 2 allowances allocated to the TR
SO2 Group 2 units at the source, or in
each appropriate Allowance
Management System account the TR
SO2 Group 2 allowances auctioned to
TR SO2 Group 2 units, in accordance
with § 97.711(a), or with a SIP revision
approved under § 52.39(h) or (i) of this
chapter, for the control period in 2014
and 2015.
(d) By July 1, 2014, the Administrator
will record in each TR SO2 Group 2
source’s compliance account the TR SO2
Group 2 allowances allocated to the TR
SO2 Group 2 units at the source, or in
each appropriate Allowance
Management System account the TR
SO2 Group 2 allowances auctioned to
TR SO2 Group 2 units, in accordance
with § 97.711(a), or with a SIP revision
approved under § 52.39(h) or (i) of this
chapter, for the control period in 2016
and 2017.
(e) By July 1, 2015, the Administrator
will record in each TR SO2 Group 2
source’s compliance account the TR SO2
Group 2 allowances allocated to the TR
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Jkt 223001
SO2 Group 2 units at the source, or in
each appropriate Allowance
Management System account the TR
SO2 Group 2 allowances auctioned to
TR SO2 Group 2 units, in accordance
with § 97.711(a), or with a SIP revision
approved under § 52.39(h) or (i) of this
chapter, for the control period in 2018
and 2019.
(f) By July 1, 2016 and July 1 of each
year thereafter, the Administrator will
record in each TR SO2 Group 2 source’s
compliance account the TR SO2 Group
2 allowances allocated to the TR SO2
Group 2 units at the source, or in each
appropriate Allowance Management
System account the TR SO2 Group 2
allowances auctioned to TR SO2 Group
2 units, in accordance with § 97.711(a),
or with a SIP revision approved under
§ 52.39(h) and (i) of this chapter, for the
control period in the fourth year after
the year of the applicable recordation
deadline under this paragraph.
(g) By August 1, 2012 and August 1
of each year thereafter, the
Administrator will record in each TR
SO2 Group 2 source’s compliance
account the TR SO2 Group 2 allowances
allocated to the TR SO2 Group 2 units
at the source, or in each appropriate
Allowance Management System account
the TR SO2 Group 2 allowances
auctioned to TR SO2 Group 2 units, in
accordance with § 97.712(a)(2) through
(8) and (12), or with a SIP revision
approved under § 52.39(h) and (i) of this
chapter, for the control period in the
year of the applicable recordation
deadline under this paragraph.
(h) By August 1, 2012 and August 1
of each year thereafter, the
Administrator will record in each TR
SO2 Group 2 source’s compliance
account the TR SO2 Group 2 allowances
allocated to the TR SO2 Group 2 units
at the source in accordance with
§ 97.712(b)(2) through (8) and (12) for
the control period in the year of the
applicable recordation deadline under
this paragraph.
(i) By February 15, 2013 and February
15 of each year thereafter, the
Administrator will record in each TR
SO2 Group 2 source’s compliance
account the TR SO2 Group 2 allowances
allocated to the TR SO2 Group 2 units
at the source in accordance with
§ 97.712(a)(9) through (12), for the
control period in the year before the
year of the applicable recordation
deadline under this paragraph.
(j) By the date on which any
allocation or auction results, other than
an allocation or auction results,
described in paragraphs (a) through (i)
of this section, of TR SO2 Group 2
allowances to a recipient is made by or
are submitted to the Administrator in
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Fmt 4701
Sfmt 4700
accordance with § 97.711 or § 97.712 or
with a SIP revision approved under
§ 52.39(h) or (i) of this chapter, the
Administrator will record such
allocation or auction results in the
appropriate Allowance Management
System account.
(k) When recording the allocation or
auction of TR SO2 Group 2 allowances
to a TR SO2 Group 2 unit or other entity
in an Allowance Management System
account, the Administrator will assign
each TR SO2 Group 2 allowance a
unique identification number that will
include digits identifying the year of the
control period for which the TR SO2
Group 2 allowance is allocated or
auctioned.
§ 97.722 Submission of TR SO2 Group 2
allowance transfers.
(a) An authorized account
representative seeking recordation of a
TR SO2 Group 2 allowance transfer shall
submit the transfer to the Administrator.
(b) A TR SO2 Group 2 allowance
transfer shall be correctly submitted if:
(1) The transfer includes the following
elements, in a format prescribed by the
Administrator:
(i) The account numbers established
by the Administrator for both the
transferor and transferee accounts;
(ii) The serial number of each TR SO2
Group 2 allowance that is in the
transferor account and is to be
transferred; and
(iii) The name and signature of the
authorized account representative of the
transferor account and the date signed;
and
(2) When the Administrator attempts
to record the transfer, the transferor
account includes each TR SO2 Group 2
allowance identified by serial number in
the transfer.
§ 97.723 Recordation of TR SO2 Group 2
allowance transfers.
(a) Within 5 business days (except as
provided in paragraph (b) of this
section) of receiving a TR SO2 Group 2
allowance transfer that is correctly
submitted under § 97.722, the
Administrator will record a TR SO2
Group 2 allowance transfer by moving
each TR SO2 Group 2 allowance from
the transferor account to the transferee
account as specified in the transfer.
(b) A TR SO2 Group 2 allowance
transfer to or from a compliance account
that is submitted for recordation after
the allowance transfer deadline for a
control period and that includes any TR
SO2 Group 2 allowances allocated for
any control period before such
allowance transfer deadline will not be
recorded until after the Administrator
completes the deductions from such
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compliance account under § 97.724 for
the control period immediately before
such allowance transfer deadline.
(c) Where a TR SO2 Group 2
allowance transfer is not correctly
submitted under § 97.722, the
Administrator will not record such
transfer.
(d) Within 5 business days of
recordation of a TR SO2 Group 2
allowance transfer under paragraphs (a)
and (b) of the section, the Administrator
will notify the authorized account
representatives of both the transferor
and transferee accounts.
(e) Within 10 business days of receipt
of a TR SO2 Group 2 allowance transfer
that is not correctly submitted under
§ 97.722, the Administrator will notify
the authorized account representatives
of both accounts subject to the transfer
of:
(1) A decision not to record the
transfer, and
(2) The reasons for such nonrecordation.
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§ 97.724 Compliance with TR SO2 Group 2
emissions limitation.
(a) Availability for deduction for
compliance. TR SO2 Group 2 allowances
are available to be deducted for
compliance with a source’s TR SO2
Group 2 emissions limitation for a
control period in a given year only if the
TR SO2 Group 2 allowances:
(1) Were allocated for such control
period or a control period in a prior
year; and
(2) Are held in the source’s
compliance account as of the allowance
transfer deadline for such control
period.
(b) Deductions for compliance. After
the recordation, in accordance with
§ 97.723, of TR SO2 Group 2 allowance
transfers submitted by the allowance
transfer deadline for a control period in
a given year, the Administrator will
deduct from each source’s compliance
account TR SO2 Group 2 allowances
available under paragraph (a) of this
section in order to determine whether
the source meets the TR SO2 Group 2
emissions limitation for such control
period, as follows:
(1) Until the amount of TR SO2 Group
2 allowances deducted equals the
number of tons of total SO2 emissions
from all TR SO2 Group 2 units at the
source for such control period; or
(2) If there are insufficient TR SO2
Group 2 allowances to complete the
deductions in paragraph (b)(1) of this
section, until no more TR SO2 Group 2
allowances available under paragraph
(a) of this section remain in the
compliance account.
(c)(1) Identification of TR SO2 Group
2 allowances by serial number. The
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authorized account representative for a
source’s compliance account may
request that specific TR SO2 Group 2
allowances, identified by serial number,
in the compliance account be deducted
for emissions or excess emissions for a
control period in a given year in
accordance with paragraph (b) or (d) of
this section. In order to be complete,
such request shall be submitted to the
Administrator by the allowance transfer
deadline for such control period and
include, in a format prescribed by the
Administrator, the identification of the
TR SO2 Group 2 source and the
appropriate serial numbers.
(2) First-in, first-out. The
Administrator will deduct TR SO2
Group 2 allowances under paragraph (b)
or (d) of this section from the source’s
compliance account in accordance with
a complete request under paragraph
(c)(1) of this section or, in the absence
of such request or in the case of
identification of an insufficient amount
of TR SO2 Group 2 allowances in such
request, on a first-in, first-out
accounting basis in the following order:
(i) Any TR SO2 Group 2 allowances
that were allocated to the units at the
source and not transferred out of the
compliance account, in the order of
recordation; and then
(ii) Any TR SO2 Group 2 allowances
that were allocated to any unit and
transferred to and recorded in the
compliance account pursuant to this
subpart, in the order of recordation.
(d) Deductions for excess emissions.
After making the deductions for
compliance under paragraph (b) of this
section for a control period in a year in
which the TR SO2 Group 2 source has
excess emissions, the Administrator will
deduct from the source’s compliance
account an amount of TR SO2 Group 2
allowances, allocated for a control
period in a prior year or the control
period in the year of the excess
emissions or in the immediately
following year, equal to two times the
number of tons of the source’s excess
emissions.
(e) Recordation of deductions. The
Administrator will record in the
appropriate compliance account all
deductions from such an account under
paragraphs (b) and (d) of this section.
§ 97.725 Compliance with TR SO2 Group 2
assurance provisions.
(a) Availability for deduction. TR SO2
Group 2 allowances are available to be
deducted for compliance with the TR
SO2 Group 2 assurance provisions for a
control period in a given year by the
owners and operators of a group of one
or more TR SO2 Group 2 sources and
units in a State (and Indian country
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48477
within the borders of such State) only if
the TR SO2 Group 2 allowances:
(1) Were allocated for a control period
in a prior year or the control period in
the given year or in the immediately
following year; and
(2) Are held in the assurance account,
established by the Administrator for
such owners and operators of such
group of TR SO2 Group 2 sources and
units in such State (and Indian country
within the borders of such State) under
paragraph (b)(3) of this section, as of the
deadline established in paragraph (b)(4)
of this section.
(b) Deductions for compliance. The
Administrator will deduct TR SO2
Group 2 allowances available under
paragraph (a) of this section for
compliance with the TR SO2 Group 2
assurance provisions for a State for a
control period in a given year in
accordance with the following
procedures:
(1) By June 1, 2013 and June 1 of each
year thereafter, the Administrator will:
(i) Calculate, for each State (and
Indian country within the borders of
such State), the total SO2 emissions
from all TR SO2 Group 2 units at TR SO2
Group 2 sources in the State (and Indian
country within the borders of such
State) during the control period in the
year before the year of this calculation
deadline and the amount, if any, by
which such total SO2 emissions exceed
the State assurance level as described in
§ 97.706(c)(2)(iii); and
(ii) Promulgate a notice of data
availability of the results of the
calculations required in paragraph
(b)(1)(i) of this section, including
separate calculations of the SO2
emissions from each TR SO2 Group 2
source.
(2) For each notice of data availability
required in paragraph (b)(1)(ii) of this
section and for any State (and Indian
country within the borders of such
State) identified in such notice as
having TR SO2 Group 2 units with total
SO2 emissions exceeding the State
assurance level for a control period in
a given year, as described in
§ 97.706(c)(2)(iii):
(i) By July 1 immediately after the
promulgation of such notice, the
designated representative of each TR
SO2 Group 2 source in each such State
(and Indian country within the borders
of such State) shall submit a statement,
in a format prescribed by the
Administrator, providing for each TR
SO2 Group 2 unit (if any) at the source
that operates during, but is not allocated
an amount of TR SO2 Group 2
allowances for, such control period, the
unit’s allowable SO2 emission rate for
such control period and, if such rate is
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expressed in lb per mmBtu, the unit’s
heat rate.
(ii) By August 1 immediately after the
promulgation of such notice, the
Administrator will calculate, for each
such State (and Indian country within
the borders of such State) and such
control period and each common
designated representative for such
control period for a group of one or
more TR SO2 Group 2 sources and units
in the State (and Indian country within
the borders of such State), the common
designated representative’s share of the
total SO2 emissions from all TR SO2
Group 2 units at TR SO2 Group 2
sources in the State (and Indian country
within the borders of such State), the
common designated representative’s
assurance level, and the amount (if any)
of TR SO2 Group 2 allowances that the
owners and operators of such group of
sources and units must hold in
accordance with the calculation formula
in § 97.706(c)(2)(i) and will promulgate
a notice of data availability of the results
of these calculations.
(iii) The Administrator will provide
an opportunity for submission of
objections to the calculations referenced
by the notice of data availability
required in paragraph (b)(2)(ii) of this
section and the calculations referenced
by the relevant notice of data
availability required in paragraph
(b)(1)(i) of this section.
(A) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations referenced in
the relevant notice required under
paragraph (b)(1)(ii) of this section and
referenced in the notice required under
paragraph (b)(2)(ii) of this section are in
accordance with § 97.706(c)(2)(iii),
§§ 97.706(b) and 97.730 through 97.735,
the definitions of ‘‘common designated
representative’’, ‘‘common designated
representative’s assurance level’’, and
‘‘common designated representative’s
share’’ in § 97.702, and the calculation
formula in § 97.706(c)(2)(i).
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are in accordance with
the provisions referenced in paragraph
(b)(2)(iii)(A) of this section. By October
1 immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of data availability
of any adjustments that the
Administrator determines to be
necessary and the reasons for accepting
or rejecting any objections submitted in
accordance with paragraph (b)(2)(iii)(A)
of this section.
(3) For any State (and Indian country
within the borders of such State)
referenced in each notice of data
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availability required in paragraph
(b)(2)(iii)(B) of this section as having TR
SO2 Group 2 units with total SO2
emissions exceeding the State assurance
level for a control period in a given year,
the Administrator will establish one
assurance account for each set of owners
and operators referenced, in the notice
of data availability required under
paragraph (b)(2)(iii)(B) of this section, as
all of the owners and operators of a
group of TR SO2 Group 2 sources and
units in the State (and Indian country
within the borders of such State) having
a common designated representative for
such control period and as being
required to hold TR SO2 Group 2
allowances.
(4)(i) As of midnight of November 1
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(2)(iii)(B) of this section,
the owners and operators described in
paragraph (b)(3) of this section shall
hold in the assurance account
established for them and for the
appropriate TR SO2 Group 2 sources, TR
SO2 Group 2 units, and State (and
Indian country within the borders of
such State) under paragraph (b)(3) of
this section a total amount of TR SO2
Group 2 allowances, available for
deduction under paragraph (a) of this
section, equal to the amount such
owners and operators are required to
hold with regard to such sources, units
and State (and Indian country within
the borders of such State) as calculated
by the Administrator and referenced in
such notice.
(ii) Notwithstanding the allowanceholding deadline specified in paragraph
(b)(4)(i) of this section, if November 1 is
not a business day, then such
allowance-holding deadline shall be
midnight of the first business day
thereafter.
(5) After November 1 (or the date
described in paragraph (b)(4)(ii) of this
section) immediately after the
promulgation of each notice of data
availability required in paragraph
(b)(2)(iii)(B) of this section and after the
recordation, in accordance with
§ 97.723, of TR SO2 Group 2 allowance
transfers submitted by midnight of such
date, the Administrator will determine
whether the owners and operators
described in paragraph (b)(3) of this
section hold, in the assurance account
for the appropriate TR SO2 Group 2
sources, TR SO2 Group 2 units, and
State (and Indian country within the
borders of such State) established under
paragraph (b)(3) of this section, the
amount of TR SO2 Group 2 allowances
available under paragraph (a) of this
section that the owners and operators
are required to hold with regard to such
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sources, units, and State (and Indian
country within the borders of such
State) as calculated by the
Administrator and referenced in the
notice required in paragraph
(b)(2)(iii)(B) of this section.
(6) Notwithstanding any other
provision of this subpart and any
revision, made by or submitted to the
Administrator after the promulgation of
the notice of data availability required
in paragraph (b)(2)(iii)(B) of this section
for a control period in a given year, of
any data used in making the
calculations referenced in such notice,
the amounts of TR SO2 Group 2
allowances that the owners and
operators are required to hold in
accordance with § 97.706(c)(2)(i) for
such control period shall continue to be
such amounts as calculated by the
Administrator and referenced in such
notice required in paragraph
(b)(2)(iii)(B) of this section, except as
follows:
(i) If any such data are revised by the
Administrator as a result of a decision
in or settlement of litigation concerning
such data on appeal under part 78 of
this chapter of such notice, or on appeal
under section 307 of the Clean Air Act
of a decision rendered under part 78 of
this chapter on appeal of such notice,
then the Administrator will use the data
as so revised to recalculate the amounts
of TR SO2 Group 2 allowances that
owners and operators are required to
hold in accordance with the calculation
formula in § 97.706(c)(2)(i) for such
control period with regard to the TR SO2
Group 2 sources, TR SO2 Group 2 units,
and State (and Indian country within
the borders of such State) involved,
provided that such litigation under part
78 of this chapter, or the proceeding
under part 78 of this chapter that
resulted in the decision appealed in
such litigation under section 307 of the
Clean Air Act, was initiated no later
than 30 days after promulgation of such
notice required in paragraph
(b)(2)(iii)(B) of this section.
(ii) If any such data are revised by the
owners and operators of a TR SO2 Group
2 source and TR SO2 Group 2 unit
whose designated representative
submitted such data under paragraph
(b)(2)(i) of this section, as a result of a
decision in or settlement of litigation
concerning such submission, then the
Administrator will use the data as so
revised to recalculate the amounts of TR
SO2 Group 2 allowances that owners
and operators are required to hold in
accordance with the calculation formula
in § 97.706(c)(2)(i) for such control
period with regard to the TR SO2 Group
2 sources, TR SO2 Group 2 units, and
State (and Indian country within the
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borders of such State) involved,
provided that such litigation was
initiated no later than 30 days after
promulgation of such notice required in
paragraph (b)(2)(iii)(B) of this section.
(iii) If the revised data are used to
recalculate, in accordance with
paragraphs (b)(6)(i) and (ii) of this
section, the amount of TR SO2 Group 2
allowances that the owners and
operators are required to hold for such
control period with regard to the TR SO2
Group 2 sources, TR SO2 Group 2 units,
and State (and Indian country within
the borders of such State) involved—
(A) Where the amount of TR SO2
Group 2 allowances that the owners and
operators are required to hold increases
as a result of the use of all such revised
data, the Administrator will establish a
new, reasonable deadline on which the
owners and operators shall hold the
additional amount of TR SO2 Group 2
allowances in the assurance account
established by the Administrator for the
appropriate TR SO2 Group 2 sources, TR
SO2 Group 2 units, and State (and
Indian country within the borders of
such State) under paragraph (b)(3) of
this section. The owners’ and operators’
failure to hold such additional amount,
as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owners’ and operators’ failure
to hold such additional amount, as
required, as of the new deadline shall be
a violation of the Clean Air Act. Each
TR SO2 Group 2 allowance that the
owners and operators fail to hold as
required as of the new deadline, and
each day in such control period, shall be
a separate violation of the Clean Air Act.
(B) For the owners and operators for
which the amount of TR SO2 Group 2
allowances required to be held
decreases as a result of the use of all
such revised data, the Administrator
will record, in all accounts from which
TR SO2 Group 2 allowances were
transferred by such owners and
operators for such control period to the
assurance account established by the
Administrator for the appropriate at TR
SO2 Group 2 sources, TR SO2 Group 2
units, and State (and Indian country
within the borders of such State) under
paragraph (b)(3) of this section, a total
amount of the TR SO2 Group 2
allowances held in such assurance
account equal to the amount of the
decrease. If TR SO2 Group 2 allowances
were transferred to such assurance
account from more than one account,
the amount of TR SO2 Group 2
allowances recorded in each such
transferor account will be in proportion
to the percentage of the total amount of
TR SO2 Group 2 allowances transferred
to such assurance account for such
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control period from such transferor
account.
(C) Each TR SO2 Group 2 allowance
held under paragraph (b)(6)(iii)(A) of
this section as a result of recalculation
of requirements under the TR SO2
Group 2 assurance provisions for such
control period must be a TR SO2 Group
2 allowance allocated for a control
period in a year before or the year
immediately following, or in the same
year as, the year of such control period.
§ 97.726
Banking.
(a) A TR SO2 Group 2 allowance may
be banked for future use or transfer in
a compliance account or a general
account in accordance with paragraph
(b) of this section.
(b) Any TR SO2 Group 2 allowance
that is held in a compliance account or
a general account will remain in such
account unless and until the TR SO2
Group 2 allowance is deducted or
transferred under § 97.711(c), § 97.723,
§ 97.724, § 97.725, § 97.727, or § 97.728.
§ 97.727
Account error.
The Administrator may, at his or her
sole discretion and on his or her own
motion, correct any error in any
Allowance Management System
account. Within 10 business days of
making such correction, the
Administrator will notify the authorized
account representative for the account.
§ 97.728 Administrator’s action on
submissions.
(a) The Administrator may review and
conduct independent audits concerning
any submission under the TR SO2
Group 2 Trading Program and make
appropriate adjustments of the
information in the submission.
(b) The Administrator may deduct TR
SO2 Group 2 allowances from or transfer
TR SO2 Group 2 allowances to a
compliance account or an assurance
account, based on the information in a
submission, as adjusted under
paragraph (a)(1) of this section, and
record such deductions and transfers.
§ 97.729
[Reserved]
§ 97.730 General monitoring,
recordkeeping, and reporting requirements.
The owners and operators, and to the
extent applicable, the designated
representative, of a TR SO2 Group 2
unit, shall comply with the monitoring,
recordkeeping, and reporting
requirements as provided in this subpart
and subparts F and G of part 75 of this
chapter. For purposes of applying such
requirements, the definitions in § 97.702
and in § 72.2 of this chapter shall apply,
the terms ‘‘affected unit,’’ ‘‘designated
representative,’’ and ‘‘continuous
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48479
emission monitoring system’’ (or
‘‘CEMS’’) in part 75 of this chapter shall
be deemed to refer to the terms ‘‘TR SO2
Group 2 unit,’’ ‘‘designated
representative,’’ and ‘‘continuous
emission monitoring system’’ (or
‘‘CEMS’’) respectively as defined in
§ 97.702, and the term ‘‘newly affected
unit’’ shall be deemed to mean ‘‘newly
affected TR SO2 Group 2 unit’’. The
owner or operator of a unit that is not
a TR SO2 Group 2 unit but that is
monitored under § 75.16(b)(2) of this
chapter shall comply with the same
monitoring, recordkeeping, and
reporting requirements as a TR SO2
Group 2 unit.
(a) Requirements for installation,
certification, and data accounting. The
owner or operator of each TR SO2 Group
2 unit shall:
(1) Install all monitoring systems
required under this subpart for
monitoring SO2 mass emissions and
individual unit heat input (including all
systems required to monitor SO2
concentration, stack gas moisture
content, stack gas flow rate, CO2 or O2
concentration, and fuel flow rate, as
applicable, in accordance with §§ 75.11
and 75.16 of this chapter);
(2) Successfully complete all
certification tests required under
§ 97.731 and meet all other
requirements of this subpart and part 75
of this chapter applicable to the
monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure
the data from the monitoring systems
under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as
provided in paragraph (e) of this
section, the owner or operator shall
meet the monitoring system certification
and other requirements of paragraphs
(a)(1) and (2) of this section on or before
the following dates and shall record,
report, and quality-assure the data from
the monitoring systems under paragraph
(a)(1) of this section on and after the
following dates.
(1) For the owner or operator of a TR
SO2 Group 2 unit that commences
commercial operation before July 1,
2011, January 1, 2012.
(2) For the owner or operator of a TR
SO2 Group 2 unit that commences
commercial operation on or after July 1,
2011, by the later of the following:
(i) January 1, 2012; or
(ii) 180 calendar days after the date on
which the unit commences commercial
operation.
(3) The owner or operator of a TR SO2
Group 2 unit for which construction of
a new stack or flue or installation of
add-on SO2 emission controls is
completed after the applicable deadline
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under paragraph (b)(1) or (2) of this
section shall meet the requirements of
§§ 75.4(e)(1) through (e)(4) of this
chapter, except that:
(i) Such requirements shall apply to
the monitoring systems required under
§ 97.730 through § 97.735, rather than
the monitoring systems required under
part 75 of this chapter;
(ii) SO2 concentration, stack gas
moisture content, stack gas volumetric
flow rate, and O2 or CO2 concentration
data shall be determined and reported,
rather than the data listed in § 75.4(e)(2)
of this chapter; and
(iii) Any petition for another
procedure under § 75.4(e)(2) of this
chapter shall be submitted under
§ 97.735, rather than § 75.66.
(c) Reporting data. The owner or
operator of a TR SO2 Group 2 unit that
does not meet the applicable
compliance date set forth in paragraph
(b) of this section for any monitoring
system under paragraph (a)(1) of this
section shall, for each such monitoring
system, determine, record, and report
maximum potential (or, as appropriate,
minimum potential) values for SO2
concentration, stack gas flow rate, stack
gas moisture content, fuel flow rate, and
any other parameters required to
determine SO2 mass emissions and heat
input in accordance with § 75.31(b)(2)
or (c)(3) of this chapter or section 2.4 of
appendix D to part 75 of this chapter, as
applicable.
(d) Prohibitions. (1) No owner or
operator of a TR SO2 Group 2 unit shall
use any alternative monitoring system,
alternative reference method, or any
other alternative to any requirement of
this subpart without having obtained
prior written approval in accordance
with § 97.735.
(2) No owner or operator of a TR SO2
Group 2 unit shall operate the unit so
as to discharge, or allow to be
discharged, SO2 to the atmosphere
without accounting for all such SO2 in
accordance with the applicable
provisions of this subpart and part 75 of
this chapter.
(3) No owner or operator of a TR SO2
Group 2 unit shall disrupt the
continuous emission monitoring system,
any portion thereof, or any other
approved emission monitoring method,
and thereby avoid monitoring and
recording SO2 mass discharged into the
atmosphere or heat input, except for
periods of recertification or periods
when calibration, quality assurance
testing, or maintenance is performed in
accordance with the applicable
provisions of this subpart and part 75 of
this chapter.
(4) No owner or operator of a TR SO2
Group 2 unit shall retire or permanently
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discontinue use of the continuous
emission monitoring system, any
component thereof, or any other
approved monitoring system under this
subpart, except under any one of the
following circumstances:
(i) During the period that the unit is
covered by an exemption under § 97.705
that is in effect;
(ii) The owner or operator is
monitoring emissions from the unit with
another certified monitoring system
approved, in accordance with the
applicable provisions of this subpart
and part 75 of this chapter, by the
Administrator for use at that unit that
provides emission data for the same
pollutant or parameter as the retired or
discontinued monitoring system; or
(iii) The designated representative
submits notification of the date of
certification testing of a replacement
monitoring system for the retired or
discontinued monitoring system in
accordance with § 97.731(d)(3)(i).
(e) Long-term cold storage. The owner
or operator of a TR SO2 Group 2 unit is
subject to the applicable provisions of
§ 75.4(d) of this chapter concerning
units in long-term cold storage.
§ 97.731 Initial monitoring system
certification and recertification procedures.
(a) The owner or operator of a TR SO2
Group 2 unit shall be exempt from the
initial certification requirements of this
section for a monitoring system under
§ 97.730(a)(1) if the following conditions
are met:
(1) The monitoring system has been
previously certified in accordance with
part 75 of this chapter; and
(2) The applicable quality-assurance
and quality-control requirements of
§ 75.21 of this chapter and appendices
B and D to part 75 of this chapter are
fully met for the certified monitoring
system described in paragraph (a)(1) of
this section.
(b) The recertification provisions of
this section shall apply to a monitoring
system under § 97.730(a)(1) that is
exempt from initial certification
requirements under paragraph (a) of this
section.
(c) [Reserved]
(d) Except as provided in paragraph
(a) of this section, the owner or operator
of a TR SO2 Group 2 unit shall comply
with the following initial certification
and recertification procedures, for a
continuous monitoring system (i.e., a
continuous emission monitoring system
and an excepted monitoring system
under appendix D to part 75 of this
chapter) under § 97.730(a)(1). The
owner or operator of a unit that qualifies
to use the low mass emissions excepted
monitoring methodology under § 75.19
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of this chapter or that qualifies to use an
alternative monitoring system under
subpart E of part 75 of this chapter shall
comply with the procedures in
paragraph (e) or (f) of this section
respectively.
(1) Requirements for initial
certification. The owner or operator
shall ensure that each continuous
monitoring system under § 97.730(a)(1)
(including the automated data
acquisition and handling system)
successfully completes all of the initial
certification testing required under
§ 75.20 of this chapter by the applicable
deadline in § 97.730(b). In addition,
whenever the owner or operator installs
a monitoring system to meet the
requirements of this subpart in a
location where no such monitoring
system was previously installed, initial
certification in accordance with § 75.20
of this chapter is required.
(2) Requirements for recertification.
Whenever the owner or operator makes
a replacement, modification, or change
in any certified continuous emission
monitoring system under § 97.730(a)(1)
that may significantly affect the ability
of the system to accurately measure or
record SO2 mass emissions or heat input
rate or to meet the quality-assurance and
quality-control requirements of § 75.21
of this chapter or appendix B to part 75
of this chapter, the owner or operator
shall recertify the monitoring system in
accordance with § 75.20(b) of this
chapter. Furthermore, whenever the
owner or operator makes a replacement,
modification, or change to the flue gas
handling system or the unit’s operation
that may significantly change the stack
flow or concentration profile, the owner
or operator shall recertify each
continuous emission monitoring system
whose accuracy is potentially affected
by the change, in accordance with
§ 75.20(b) of this chapter. Examples of
changes to a continuous emission
monitoring system that require
recertification include: Replacement of
the analyzer, complete replacement of
an existing continuous emission
monitoring system, or change in
location or orientation of the sampling
probe or site. Any fuel flowmeter system
under § 97.730(a)(1) is subject to the
recertification requirements in
§ 75.20(g)(6) of this chapter.
(3) Approval process for initial
certification and recertification. For
initial certification of a continuous
monitoring system under § 97.730(a)(1),
paragraphs (d)(3)(i) through (v) of this
section apply. For recertifications of
such monitoring systems, paragraphs
(d)(3)(i) through (iv) of this section and
the procedures in §§ 75.20(b)(5) and
(g)(7) of this chapter (in lieu of the
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procedures in paragraph (d)(3)(v) of this
section) apply, provided that in
applying paragraphs (d)(3)(i) through
(iv) of this section, the words
‘‘certification’’ and ‘‘initial certification’’
are replaced by the word
‘‘recertification’’ and the word
‘‘certified’’ is replaced by with the word
‘‘recertified’’.
(i) Notification of certification. The
designated representative shall submit
to the appropriate EPA Regional Office
and the Administrator written notice of
the dates of certification testing, in
accordance with § 97.733.
(ii) Certification application. The
designated representative shall submit
to the Administrator a certification
application for each monitoring system.
A complete certification application
shall include the information specified
in § 75.63 of this chapter.
(iii) Provisional certification date. The
provisional certification date for a
monitoring system shall be determined
in accordance with § 75.20(a)(3) of this
chapter. A provisionally certified
monitoring system may be used under
the TR SO2 Group 2 Trading Program for
a period not to exceed 120 days after
receipt by the Administrator of the
complete certification application for
the monitoring system under paragraph
(d)(3)(ii) of this section. Data measured
and recorded by the provisionally
certified monitoring system, in
accordance with the requirements of
part 75 of this chapter, will be
considered valid quality-assured data
(retroactive to the date and time of
provisional certification), provided that
the Administrator does not invalidate
the provisional certification by issuing a
notice of disapproval within 120 days of
the date of receipt of the complete
certification application by the
Administrator.
(iv) Certification application approval
process. The Administrator will issue a
written notice of approval or
disapproval of the certification
application to the owner or operator
within 120 days of receipt of the
complete certification application under
paragraph (d)(3)(ii) of this section. In the
event the Administrator does not issue
such a notice within such 120-day
period, each monitoring system that
meets the applicable performance
requirements of part 75 of this chapter
and is included in the certification
application will be deemed certified for
use under the TR SO2 Group 2 Trading
Program.
(A) Approval notice. If the
certification application is complete and
shows that each monitoring system
meets the applicable performance
requirements of part 75 of this chapter,
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then the Administrator will issue a
written notice of approval of the
certification application within 120
days of receipt.
(B) Incomplete application notice. If
the certification application is not
complete, then the Administrator will
issue a written notice of incompleteness
that sets a reasonable date by which the
designated representative must submit
the additional information required to
complete the certification application. If
the designated representative does not
comply with the notice of
incompleteness by the specified date,
then the Administrator may issue a
notice of disapproval under paragraph
(d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the
certification application shows that any
monitoring system does not meet the
performance requirements of part 75 of
this chapter or if the certification
application is incomplete and the
requirement for disapproval under
paragraph (d)(3)(iv)(B) of this section is
met, then the Administrator will issue a
written notice of disapproval of the
certification application. Upon issuance
of such notice of disapproval, the
provisional certification is invalidated
by the Administrator and the data
measured and recorded by each
uncertified monitoring system shall not
be considered valid quality-assured data
beginning with the date and hour of
provisional certification (as defined
under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The
Administrator may issue a notice of
disapproval of the certification status of
a monitor in accordance with
§ 97.732(b).
(v) Procedures for loss of certification.
If the Administrator issues a notice of
disapproval of a certification
application under paragraph
(d)(3)(iv)(C) of this section or a notice of
disapproval of certification status under
paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall
substitute the following values, for each
disapproved monitoring system, for
each hour of unit operation during the
period of invalid data specified under
§ 75.20(a)(4)(iii), § 75.20(g)(7), or
§ 75.21(e) of this chapter and continuing
until the applicable date and hour
specified under § 75.20(a)(5)(i) or (g)(7)
of this chapter:
(1) For a disapproved SO2 pollutant
concentration monitor and disapproved
flow monitor, respectively, the
maximum potential concentration of
SO2 and the maximum potential flow
rate, as defined in sections 2.1.1.1 and
2.1.4.1 of appendix A to part 75 of this
chapter.
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(2) For a disapproved moisture
monitoring system and disapproved
diluent gas monitoring system,
respectively, the minimum potential
moisture percentage and either the
maximum potential CO2 concentration
or the minimum potential O2
concentration (as applicable), as defined
in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(3) For a disapproved fuel flowmeter
system, the maximum potential fuel
flow rate, as defined in section 2.4.2.1
of appendix D to part 75 of this chapter.
(B) The designated representative
shall submit a notification of
certification retest dates and a new
certification application in accordance
with paragraphs (d)(3)(i) and (ii) of this
section.
(C) The owner or operator shall repeat
all certification tests or other
requirements that were failed by the
monitoring system, as indicated in the
Administrator’s notice of disapproval,
no later than 30 unit operating days
after the date of issuance of the notice
of disapproval.
(e) The owner or operator of a unit
qualified to use the low mass emissions
(LME) excepted methodology under
§ 75.19 of this chapter shall meet the
applicable certification and
recertification requirements in
§§ 75.19(a)(2) and 75.20(h) of this
chapter. If the owner or operator of such
a unit elects to certify a fuel flowmeter
system for heat input determination, the
owner or operator shall also meet the
certification and recertification
requirements in § 75.20(g) of this
chapter.
(f) The designated representative of
each unit for which the owner or
operator intends to use an alternative
monitoring system approved by the
Administrator under subpart E of part
75 of this chapter shall comply with the
applicable notification and application
procedures of § 75.20(f) of this chapter.
§ 97.732 Monitoring system out-of-control
periods.
(a) General provisions. Whenever any
monitoring system fails to meet the
quality-assurance and quality-control
requirements or data validation
requirements of part 75 of this chapter,
data shall be substituted using the
applicable missing data procedures in
subpart D or appendix D to part 75 of
this chapter.
(b) Audit decertification. Whenever
both an audit of a monitoring system
and a review of the initial certification
or recertification application reveal that
any monitoring system should not have
been certified or recertified because it
did not meet a particular performance
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specification or other requirement under
§ 97.731 or the applicable provisions of
part 75 of this chapter, both at the time
of the initial certification or
recertification application submission
and at the time of the audit, the
Administrator will issue a notice of
disapproval of the certification status of
such monitoring system. For the
purposes of this paragraph, an audit
shall be either a field audit or an audit
of any information submitted to the
Administrator or any State or permitting
authority. By issuing the notice of
disapproval, the Administrator revokes
prospectively the certification status of
the monitoring system. The data
measured and recorded by the
monitoring system shall not be
considered valid quality-assured data
from the date of issuance of the
notification of the revoked certification
status until the date and time that the
owner or operator completes
subsequently approved initial
certification or recertification tests for
the monitoring system. The owner or
operator shall follow the applicable
initial certification or recertification
procedures in § 97.731 for each
disapproved monitoring system.
§ 97.733 Notifications concerning
monitoring.
The designated representative of a TR
SO2 Group 2 unit shall submit written
notice to the Administrator in
accordance with § 75.61 of this chapter.
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§ 97.734
Recordkeeping and reporting.
(a) General provisions. The designated
representative shall comply with all
recordkeeping and reporting
requirements in paragraphs (b) through
(e) of this section, the applicable
recordkeeping and reporting
requirements in subparts F and G of part
75 of this chapter, and the requirements
of § 97.714(a).
(b) Monitoring plans. The owner or
operator of a TR SO2 Group 2 unit shall
comply with requirements of § 75.62 of
this chapter.
(c) Certification applications. The
designated representative shall submit
an application to the Administrator
within 45 days after completing all
initial certification or recertification
tests required under § 97.731, including
the information required under § 75.63
of this chapter.
(d) Quarterly reports. The designated
representative shall submit quarterly
reports, as follows:
(1) The designated representative
shall report the SO2 mass emissions data
and heat input data for the TR SO2
Group 2 unit, in an electronic quarterly
report in a format prescribed by the
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Administrator, for each calendar quarter
beginning with:
(i) For a unit that commences
commercial operation before July 1,
2011, the calendar quarter covering
January 1, 2012 through March 31, 2012;
or
(ii) For a unit that commences
commercial operation on or after July 1,
2011, the calendar quarter
corresponding to the earlier of the date
of provisional certification or the
applicable deadline for initial
certification under § 97.730(b), unless
that quarter is the third or fourth quarter
of 2011, in which case reporting shall
commence in the quarter covering
January 1, 2012 through March 31, 2012.
(2) The designated representative
shall submit each quarterly report to the
Administrator within 30 days after the
end of the calendar quarter covered by
the report. Quarterly reports shall be
submitted in the manner specified in
§ 75.64 of this chapter.
(3) For TR SO2 Group 2 units that are
also subject to the Acid Rain Program,
TR NOX Annual Trading Program, or TR
NOX Ozone Season Trading Program,
quarterly reports shall include the
applicable data and information
required by subparts F through H of part
75 of this chapter as applicable, in
addition to the SO2 mass emission data,
heat input data, and other information
required by this subpart.
(4) The Administrator may review and
conduct independent audits of any
quarterly report in order to determine
whether the quarterly report meets the
requirements of this subpart and part 75
of this chapter, including the
requirement to use substitute data.
(i) The Administrator will notify the
designated representative of any
determination that the quarterly report
fails to meet any such requirements and
specify in such notification any
corrections that the Administrator
believes are necessary to make through
resubmission of the quarterly report and
a reasonable time period within which
the designated representative must
respond. Upon request by the
designated representative, the
Administrator may specify reasonable
extensions of such time period. Within
the time period (including any such
extensions) specified by the
Administrator, the designated
representative shall resubmit the
quarterly report with the corrections
specified by the Administrator, except
to the extent the designated
representative provides information
demonstrating that a specified
correction is not necessary because the
quarterly report already meets the
requirements of this subpart and part 75
PO 00000
Frm 00276
Fmt 4701
Sfmt 4700
of this chapter that are relevant to the
specified correction.
(ii) Any resubmission of a quarterly
report shall meet the requirements
applicable to the submission of a
quarterly report under this subpart and
part 75 of this chapter, except for the
deadline set forth in paragraph (d)(2) of
this section.
(e) Compliance certification. The
designated representative shall submit
to the Administrator a compliance
certification (in a format prescribed by
the Administrator) in support of each
quarterly report based on reasonable
inquiry of those persons with primary
responsibility for ensuring that all of the
unit’s emissions are correctly and fully
monitored. The certification shall state
that:
(1) The monitoring data submitted
were recorded in accordance with the
applicable requirements of this subpart
and part 75 of this chapter, including
the quality assurance procedures and
specifications; and
(2) For a unit with add-on SO2
emission controls and for all hours
where SO2 data are substituted in
accordance with § 75.34(a)(1) of this
chapter, the add-on emission controls
were operating within the range of
parameters listed in the quality
assurance/quality control program
under appendix B to part 75 of this
chapter and the substitute data values
do not systematically underestimate SO2
emissions.
§ 97.735 Petitions for alternatives to
monitoring, recordkeeping, or reporting
requirements.
(a) The designated representative of a
TR SO2 Group 2 unit may submit a
petition under § 75.66 of this chapter to
the Administrator, requesting approval
to apply an alternative to any
requirement of §§ 97.730 through
97.734.
(b) A petition submitted under
paragraph (a) of this section shall
include sufficient information for the
evaluation of the petition, including, at
a minimum, the following information:
(i) Identification of each unit and
source covered by the petition;
(ii) A detailed explanation of why the
proposed alternative is being suggested
in lieu of the requirement;
(iii) A description and diagram of any
equipment and procedures used in the
proposed alternative;
(iv) A demonstration that the
proposed alternative is consistent with
the purposes of the requirement for
which the alternative is proposed and
with the purposes of this subpart and
part 75 of this chapter and that any
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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations
ebenthall on DSK6TPTVN1PROD with RULES2
adverse effect of approving the
alternative will be de minimis; and
(v) Any other relevant information
that the Administrator may require.
VerDate Mar<15>2010
19:20 Aug 05, 2011
Jkt 223001
(c) Use of an alternative to any
requirement referenced in paragraph (a)
of this section is in accordance with this
subpart only to the extent that the
petition is approved in writing by the
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Administrator and that such use is in
accordance with such approval.
[FR Doc. 2011–17600 Filed 8–5–11; 8:45 am]
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]]>Agencies
[Federal Register Volume 76, Number 152 (Monday, August 8, 2011)]
[Rules and Regulations]
[Pages 48208-48483]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-17600]
[[Page 48207]]
Vol. 76
Monday,
No. 152
August 8, 2011
Part II
Environmental Protection Agency
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40 CFR Parts 51, 52, 72 et al.
Federal Implementation Plans: Interstate Transport of Fine Particulate
Matter and Ozone and Correction of SIP Approvals; Final Rule
Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules
and Regulations
[[Page 48208]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 52, 72, 78, and 97
[EPA-HQ-OAR-2009-0491; FRL-9436-8]
RIN 2060-AP50
Federal Implementation Plans: Interstate Transport of Fine
Particulate Matter and Ozone and Correction of SIP Approvals
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: In this action, EPA is limiting the interstate transport of
emissions of nitrogen oxides (NOX) and sulfur dioxide
(SO2) that contribute to harmful levels of fine particle
matter (PM2.5) and ozone in downwind states. EPA is
identifying emissions within 27 states in the eastern United States
that significantly affect the ability of downwind states to attain and
maintain compliance with the 1997 and 2006 fine particulate matter
national ambient air quality standards (NAAQS) and the 1997 ozone
NAAQS. Also, EPA is limiting these emissions through Federal
Implementation Plans (FIPs) that regulate electric generating units
(EGUs) in the 27 states. This action will substantially reduce adverse
air quality impacts in downwind states from emissions transported
across state lines. In conjunction with other federal and state
actions, it will help assure that all but a handful of areas in the
eastern part of the country achieve compliance with the current ozone
and PM2.5 NAAQS by the deadlines established in the Clean
Air Act (CAA or Act). The FIPs may not fully eliminate the prohibited
emissions from certain states with respect to the 1997 ozone NAAQS for
two remaining downwind areas and EPA is committed to identifying any
additional required upwind emission reductions and taking any necessary
action in a future rulemaking. In this action, EPA is also modifying
its prior approvals of certain State Implementation Plan (SIP)
submissions to rescind any statements that the submissions in question
satisfy the interstate transport requirements of the CAA or that EPA's
approval of the SIPs affects our authority to issue interstate
transport FIPs with respect to the 1997 fine particulate and 1997 ozone
standards for 22 states. EPA is also issuing a supplemental proposal to
request comment on its conclusion that six additional states
significantly affect downwind states' ability to attain and maintain
compliance with the 1997 ozone NAAQS.
DATES: This final rule is effective on October 7, 2011.
ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-HQ-OAR-2009-0491. All documents in the docket are listed on the
https://www.regulations.gov Web site. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically through https://www.regulations.gov or in hard copy at the EPA Docket Center, EPA West,
Room B102, 1301 Constitution Avenue, NW., Washington, DC. The Public
Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is (202) 566-1744, and the telephone number for the Air
Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: For general questions concerning this
action, please contact Ms. Meg Victor, Clean Air Markets Division,
Office of Atmospheric Programs, Mail Code 6204J, Environmental
Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460;
telephone number: (202) 343-9193; fax number: (202) 343-2359; e-mail
address: victor.meg@epa.gov. For legal questions, please contact Ms.
Sonja Rodman, U.S. EPA, Office of General Counsel, Mail Code 2344A,
1200 Pennsylvania Avenue, NW., Washington, DC 20460, telephone (202)
564-4079; e-mail address: rodman.sonja@epa.gov.
SUPPLEMENTARY INFORMATION:
I. Preamble Glossary of Terms and Abbreviations
The following are abbreviations of terms used in the preamble.
AQAT Air Quality Assessment Tool
ARP Acid Rain Program
BART Best Available Retrofit Technology
BACT Best Available Control Technology
CAA or Act Clean Air Act
CAIR Clean Air Interstate Rule
CAMx Comprehensive Air Quality Model with Extensions
CBI Confidential Business Information
CCR Coal Combustion Residuals
CEM Continuous Emissions Monitoring
CENRAP Central Regional Air Planning Association
CFR Code of Federal Regulations
DEQ Department of Environmental Quality
DSI Dry Sorbent Injection
EGU Electric Generating Unit
FERC Federal Energy Regulatory Commission
FGD Flue Gas Desulfurization
FIP Federal Implementation Plan
FR Federal Register
EPA U.S. Environmental Protection Agency
GHG Greenhouse Gas
GW Gigawatts
Hg Mercury
ICR Information Collection Request
IPM Integrated Planning Model
km Kilometers
lb/mmBtu Pounds Per Million British Thermal Unit
LNB Low-NOX Burners
MACT Maximum Achievable Control Technology
MATS Modeled Attainment Test Software
[mu]g/m \3\ Micrograms Per Cubic Meter
MSAT Mobile Source Air Toxics
MOVES Motor Vehicle Emission Simulator
NAAQS National Ambient Air Quality Standards
NBP NOX Budget Trading Program
NEI National Emission Inventory
NESHAP National Emissions Standards for Hazardous Air Pollutants
NOX Nitrogen Oxides
NODA Notices of Data Availability
NSPS New Source Performance Standard
NSR New Source Review
OFA Overfire Air
OSAT Ozone Source Apportionment Technique
OTAG Ozone Transport Assessment Group
ppb Parts Per Billion
PM2.5 Fine Particulate Matter, Less Than 2.5 Micrometers
PM10 Fine and Coarse Particulate Matter, Less Than 10
Micrometers
PM Particulate Matter
ppm Parts Per Million
PUC Public Utility Commission
RIA Regulatory Impact Analysis
SCR Selective Catalytic Reduction
SIP State Implementation Plan
SMOKE Sparse Matrix Operator Kernel Emissions
SNCR Selective Non-catalytic Reduction
SO2 Sulfur Dioxide
SOX Sulfur Oxides, Including Sulfur Dioxide
(SO2) and Sulfur Trioxide (SO3)
TAF Terminal Area Forecast
TCEQ Texas Commission on Environmental Quality
TIP Tribal Implementation Plan
TLN3 Tangential Low NOX
TPY Tons Per Year
TSD Technical Support Document
WRAP Western Regional Air Partnership
II. General Information
A. Does this action apply to me?
This rule affects EGUs, and regulates the following groups:
------------------------------------------------------------------------
Industry group NAICS a
------------------------------------------------------------------------
Utilities (electric, natural gas, other systems.).... 2211, 2212, 2213
------------------------------------------------------------------------
a North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists
[[Page 48209]]
the types of entities that EPA is aware of that could potentially be
regulated. Other types of entities not listed in the table could also
be regulated. To determine whether your facility would be regulated by
the proposed rule, you should carefully examine the applicability
criteria in proposed Sec. Sec. 97.404, 97.504, and 97,604.
B. How is the preamble organized?
I. Preamble Glossary of Terms and Abbreviations
II. General Information
A. Does this action apply to me?
B. How is the preamble organized?
III. Executive Summary
IV. Legal Authority, Environmental Basis, and Correction of CAIR SIP
Approvals
A. EPA's Authority for Transport Rule
B. Rulemaking History
C. Air Quality Problems and NAAQS Addressed
1. Air Quality Problems and NAAQS Addressed
2. FIP Authority for Each State and NAAQS Covered
3. Additional Information Regarding CAA Section
110(a)(2)(D)(i)(I) SIPs for States in the Transport Rule Modeling
Domain
D. Correction of CAIR SIP Approvals
V. Analysis of Downwind Air Quality and Upwind State Emissions
A. Pollutants Regulated
1. Background
2. Which pollutants did EPA propose to control for purposes of
PM2.5 and Ozone Transport?
3. Comments and Responses
B. Baseline for Pollution Transport Analysis
C. Air Quality Modeling to Identify Downwind Nonattainment and
Maintenance Receptors
1. Emission Inventories
2. Air Quality Basis for Identifying Receptors
3. How did EPA project future nonattainment and maintenance for
annual PM2.5, 24-hour PM2.5, and 8-hour ozone?
D. Pollution Transport From Upwind States
1. Choice of Air Quality Thresholds
2. Approach for Identifying Contributing Upwind States
VI. Quantification of State Emission Reductions Required
A. Cost and Air Quality Structure for Defining Reductions
1. Summary
2. Background
B. Cost of Available Emission Reductions (Step 1)
1. Development of Annual NOX and Ozone-Season
NOX Cost Curves
2. Development of SO2 Cost Curves
3. Amount of Reductions That Could Be Achieved by 2012 and 2014
C. Estimates of Air Quality Impacts (Step 2)
1. Development of the Air Quality Assessment Tool and Air
Quality Modeling Strategy
2. Utilization of AQAT to Evaluate Control Scenarios
3. Air Quality Assessment Results
D. Multi-Factor Analysis and Determination of State Emission
Budgets
1. Multi-Factor Analysis (Step 3)
2. State Emission Budgets (Step 4)
E. Approach to Power Sector Emission Variability
1. Introduction to Power Sector Variability
2. Transport Rule Variability Limits
F. Variability Limits and State Emission Budgets: State
Assurance Levels
G. How the State Emission Reduction Requirements Are Consistent
With Judicial Opinions Interpreting the Clean Air Act
VII. FIP Program Structure to Achieve Reductions
A. Overview of Air Quality-Assured Trading Programs
B. Applicability
C. Compliance Deadlines
1. Alignment With NAAQS Attainment Deadlines
2. Compliance and Deployment of Pollution Control Technologies
D. Allocation of Emission Allowances
1. Allocations to Existing Units
2. Allocations to New Units
E. Assurance Provisions
F. Penalties
G. Allowance Management System
H. Emissions Monitoring and Reporting
I. Permitting
1. Title V Permitting
2. New Source Review
J. How the Program Structure Is Consistent With Judicial
Opinions Interpreting the Clean Air Act
VIII. Economic Impacts of the Transport Rule
A. Emission Reductions
B. The Impacts on PM2.5 and Ozone of the Final
SO2 and NOX Strategy
C. Benefits
1. Human Health Benefit Analysis
2. Quantified and Monetized Visibility Benefits
3. Benefits of Reducing GHG Emissions
4. Total Monetized Benefits
5. How do the benefits in 2012 compare to 2014?
6. How do the benefits compare to the costs of this final rule?
7. What are the unquantified and non-monetized benefits of the
Transport Rule emission reductions?
D. Costs and Employment Impacts
1. Transport Rule Costs and Employment Impacts
2. End-Use Energy Efficiency
IX. Related Programs and the Transport Rule
A. Transition From the Clean Air Interstate Rule
1. Key Differences Between the Transport Rule and CAIR
2. Transition From the Clean Air Interstate Rule to the
Transport Rule
B. Interactions With NOX SIP Call
C. Interactions With Title IV Acid Rain Program
D. Other State Implementation Plan Requirements
X. Transport Rule State Implementation Plans
XI. Structure and Key Elements of Transport Rule Air Quality-Assured
Trading Program Rules
XII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
1. Consideration of Environmental Justice in the Transport Rule
Development Process and Response to Comments
2. Potential Environmental and Public Health Impacts Among
Populations Susceptible or Vulnerable to Air Pollution
3. Meaningful Public Participation
4. Summary
K. Congressional Review Act
L. Judicial Review
III. Executive Summary
The CAA section 110(a)(2)(D)(i)(I) requires states to prohibit
emissions that contribute significantly to nonattainment in, or
interfere with maintenance by, any other state with respect to any
primary or secondary NAAQS. In this final rule, EPA finds that
emissions of SO2 and NOX in 27 eastern,
midwestern, and southern states contribute significantly to
nonattainment or interfere with maintenance in one or more downwind
states with respect to one or more of three air quality standards--the
annual PM2.5 NAAQS promulgated in 1997, the 24-hour
PM2.5 NAAQS promulgated in 2006, and the ozone NAAQS
promulgated in 1997 (EPA uses the term ``states'' to include the
District of Columbia in this preamble).
These emissions are transported downwind either as SO2
and NOX or, after transformation in the atmosphere, as fine
particles or ozone. This final rule identifies emission reduction
responsibilities of upwind states, and also promulgates enforceable
FIPs to achieve the required emission reductions in each state through
cost-effective and flexible requirements for power plants. Each state
has the option of replacing these federal rules with state rules to
achieve the required amount of emission reductions from sources
selected by the state.
[[Page 48210]]
Section 110(a)(2)(D)(i)(I) of the CAA requires the elimination of
upwind state emissions that significantly contribute to nonattainment
or interfere with maintenance of a NAAQS in another state. Elimination
of these upwind state emissions may not necessarily, in itself, fully
resolve nonattainment or maintenance problems at downwind state
receptors. Downwind states also have control responsibilities because,
among other things, the Act requires each state to adopt enforceable
plans to attain and maintain air quality standards. Indeed, states have
put in place measures to reduce local emissions that contribute to
nonattainment within their borders. Section 110(a)(2)(D)(i)(I) only
requires the elimination of emissions that significantly contribute to
nonattainment or interfere with maintenance of the NAAQS in other
states; it does not shift to upwind states the responsibility for
ensuring that all areas in other states attain the NAAQS.
The reductions obtained through the Transport Rule will help all
but a few downwind areas come into attainment with and maintain the
1997 annual PM2.5 NAAQS, the 2006 24-hour PM2.5
NAAQS, and the 1997 ozone NAAQS. With respect to the annual
PM2.5 NAAQS, this rule finds that 18 states have
SO2 and annual NOX emission reduction
responsibilities, and this rule quantifies each state's full emission
reduction responsibility under section 110(a)(2)(D)(i)(I). See Table
III-1 for the list of these states. With these reductions, EPA projects
that no areas will have nonattainment or maintenance concerns with
respect to the annual PM2.5 NAAQS.
With respect to the 24-hour PM2.5 NAAQS, this rule finds
that 21 states have SO2 and annual NOX emission
reduction responsibilities, and this rule quantifies each state's full
emission reduction responsibility under 110(a)(2)(D)(i)(I). See Table
III-1 for the list of these states. In all, this rule requires emission
reductions related to interstate transport of fine particles in 23
states. With these reductions, as discussed in section VI.D of this
preamble, only one area (Liberty-Clairton) is projected to remain in
nonattainment, and three other areas (Chicago,\1\ Detroit, and
Lancaster) are projected to have remaining maintenance concerns for the
24-hour PM2.5 NAAQS.
---------------------------------------------------------------------------
\1\ This area is not currently designated as nonattainment for
the 24-hour PM2.5 standard. EPA is portraying the
receptors and counties in this area as a single 24-hour maintenance
area based on the annual PM2.5 nonattainment designation
of Chicago-Gary-Lake County, IL-IN.
---------------------------------------------------------------------------
With respect to the 1997 ozone NAAQS, this rule finds that 20
states have ozone-season NOX emission reduction
responsibilities. For 10 of these states this rule quantifies the
state's full emission reduction responsibility under section
110(a)(2)(D)(i)(I).\2\ For 10 additional states, EPA quantifies in this
rule the ozone-season NOX emission reductions that are
necessary but may not be sufficient to eliminate all significant
contribution to nonattainment and interference with maintenance in
other states.\3\ See Table III-1 for the complete list of 20 states
required to reduce ozone-season NOX emissions in this rule.
With the Transport Rule reductions, only one area (Houston) is
projected to remain in nonattainment, and one area (Baton Rouge) to
have a remaining maintenance concern with respect to the 1997 ozone
NAAQS. The 10 states upwind of either of these two areas are the states
for which additional reductions may be necessary to fully eliminate
each state's significant contribution to nonattainment and interference
with maintenance, as discussed in section VI of this preamble.\4\
---------------------------------------------------------------------------
\2\ The 10 states for which this rule quantifies the state's
full responsibility under section 110(a)(2)(D)(i)(I) with respect to
the 1997 ozone NAAQS are Florida, Maryland, New Jersey, New York,
North Carolina, Ohio, Pennsylvania, South Carolina, Virginia, and
West Virginia.
\3\ The 10 states for which this rule quantifies reductions that
are necessary but may not be sufficient to satisfy the requirements
of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS are
Alabama, Arkansas, Georgia, Illinois, Indiana, Kentucky, Louisiana,
Mississippi, Tennessee, and Texas.
\4\ This preamble uses the term ``significant contribution''
only in the context of the CAA section 110(a)(2)(D)(i)(I)
requirement that states prohibit emissions that ``contribute
significantly to nonattainment'' in any other state with respect to
any primary or secondary NAAQS. Thus, a significant contribution, as
used in this preamble, is one that is significant for purposes of
CAA section 110(a)(2)(D)(i)(I) as coming from a particular state.
---------------------------------------------------------------------------
As discussed further below, EPA's analysis also demonstrates that
six additional states should be required to reduce ozone-season
NOX emissions. EPA is issuing a supplemental proposal to
request comment on requiring ozone-season NOX reductions in
these six states. For five of these six states, EPA's analysis
identifies the state's full emission reduction responsibility under
section 110(a)(2)(D)(i)(I), and for the remaining one state EPA's
analysis identifies reductions that are necessary but may not be
sufficient to satisfy the requirements of 110(a)(2)(D)(i)(I).\5\
---------------------------------------------------------------------------
\5\ The five states addressed in the supplemental proposal for
which EPA's analysis identifies the state's full reduction
responsibility under section 110(a)(2)(D)(i)(I) with respect to the
1997 ozone NAAQS are Iowa, Kansas, Michigan, Oklahoma, and
Wisconsin. The one state addressed in the supplemental proposal for
which EPA's analysis identifies reductions that are necessary but
may not be sufficient to satisfy section 110(a)(2)(D)(i)(I) with
respect to the 1997 ozone NAAQS is Missouri.
---------------------------------------------------------------------------
On January 19, 2010, EPA proposed revisions to the 8-hour ozone
NAAQS that the Agency had issued March 12, 2008 (75 FR 2938); the
Agency intends to finalize its reconsideration in the summer of 2011.
EPA intends to propose a rule to address transport with respect to the
reconsidered 2008 ozone NAAQS as expeditiously as possible after
reconsideration is completed. EPA intends to include in that proposed
rule requirements to address any remaining significant contribution to
nonattainment and interference with maintenance with respect to the
1997 ozone NAAQS for the states identified in this final rule, or the
associated supplemental notice of proposed rulemaking, for which EPA
was unable to fully quantify the emissions that must be prohibited to
satisfy the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997
ozone NAAQS.
The Act requires EPA to conduct periodic reviews of each of the
NAAQS. When NAAQS are set or revised, the CAA requires revision of SIPs
to ensure the standards are met expeditiously and within relevant
timetables in the Act. If more protective NAAQS are promulgated, in the
case of pollutants for which interstate transport is important,
additional emission reductions to address transported pollution may be
required from the power sector, from other sectors, and from sources in
additional states. EPA will act promptly to promulgate any future rules
addressing transport with respect to revised NAAQS.
The Transport Rule requires substantial near-term emission
reductions in every covered state to address each state's significant
contribution to nonattainment and interference with maintenance
downwind. This rule achieves these reductions through FIPs that
regulate the power sector using air quality-assured trading programs
whose assurance provisions ensure that necessary reductions will occur
within every covered state. This remedy structure is substantially
similar to the preferred trading remedy structure presented in the
proposal. The Transport Rule's air quality-assured trading approach
will assure
[[Page 48211]]
environmental results in each state while providing market-based
flexibility to covered sources through interstate trading. The final
rule includes four air quality-assured trading programs: An annual
NOX trading program, an ozone-season NOX trading
program, and two separate SO2 trading programs
(``SO2 Group 1'' and ``SO2 Group 2''), as
discussed further in sections VI and VII, below.
The first phase of Transport Rule compliance commences January 1,
2012, for SO2 and annual NOX reductions and May
1, 2012, for ozone-season NOX reductions. The second phase
of Transport Rule reductions, which commences January 1, 2014,
increases the stringency of SO2 reductions in a number of
states as discussed further below.
EPA projects that with the Transport Rule, covered EGU will
substantially reduce SO2, annual NOX and ozone-
season NOX emissions, as shown in Tables III-2 and III-3,
below. This rule generally covers electric generating units that are
fossil fuel-fired boilers and turbines producing electricity for sale,
as detailed in section VII.B.
EPA is promulgating the Transport Rule in response to the remand of
the Clean Air Interstate Rule (CAIR) by the U.S. Court of Appeals for
the District of Columbia Circuit (``Court'') in 2008. CAIR, promulgated
May 12, 2005 (70 FR 25162), required 29 states to adopt and submit
revisions to their State Implementation Plans (SIPs) to eliminate
SO2 and NOX emissions that contribute
significantly to downwind nonattainment of the PM2.5 and
ozone NAAQS promulgated in July 1997. CAIR covered a similar but not
identical set of states as the Transport Rule. CAIR FIPs were
promulgated April 26, 2006 (71 FR 25328) to regulate electric
generating units in the covered states and achieve the emission
reduction requirements established by CAIR until states could submit
and obtain approval of SIPs to achieve the reductions.
In July 2008, the Court found CAIR and the CAIR FIPs unlawful.
North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008), modified on
rehearing, North Carolina v. EPA, 550 F.3d 1176, 1178 (D.C. Cir. 2008).
The Court's original decision vacated CAIR. North Carolina, 531 F.3d at
929-30. However, the Court subsequently remanded CAIR to EPA without
vacatur because it found that ``allowing CAIR to remain in effect until
it is replaced by a rule consistent with our opinion would at least
temporarily preserve the environmental values covered by CAIR.'' North
Carolina, 550 F.3d at 1178. The CAIR requirements have remained in
place while EPA has developed the Transport Rule to replace them.
EPA's approach in the Transport Rule to measure and address each
state's significant contribution to downwind nonattainment and
interference with maintenance is guided by and consistent with the
Court's opinion in North Carolina and addresses the flaws in CAIR
identified by the Court therein. This final rule also responds to
extensive public comments and stakeholder input received during the
public comment periods in response to the proposal and subsequent
Notices of Data Availability (NODAs).
In this action, EPA both identifies and addresses emissions within
states that significantly contribute to nonattainment or interfere with
maintenance in other downwind states. In developing this rule, EPA used
a state-specific methodology to identify emission reductions that must
be made in covered states to address the CAA section 110(a)(2)(D)(i)(I)
prohibition on emissions that significantly contribute to nonattainment
or interfere with maintenance in a downwind state. EPA believes this
methodology addresses the Court's concern that the approach used in
CAIR was insufficiently state-specific. EPA used detailed air quality
analysis to determine whether a state's contribution to downwind air
quality problems is at or above specific thresholds. A state is covered
by the Transport Rule if its contribution meets or exceeds one of those
air quality thresholds and the Agency identifies, using a multi-factor
analysis that takes into account both air quality and cost
considerations, emissions within the state that constitute the state's
significant contribution to nonattainment and interference with
maintenance with respect to the 1997 ozone or the 1997 annual or 2006
24-hour PM2.5 NAAQS. Section 110(a)(2)(D)(i)(I) requires
states to eliminate the emissions that constitute this ``significant
contribution'' and ``interference with maintenance.'' \6\
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\6\ In this preamble, EPA uses the terms ``significant
contribution'' and ``interference with maintenance'' to refer to the
emissions that must be prohibited pursuant to section
110(a)(2)(D)(i)(I) because they significantly contribute to
nonattainment or interfere with maintenance of the NAAQS in another
state.
---------------------------------------------------------------------------
In this final rule, EPA determined the emission reductions required
from all upwind states to eliminate significant contribution to
nonattainment and interference with maintenance with respect to the
1997 ozone, 1997 annual PM2.5, and 2006 24-hour
PM2.5 NAAQS, using, in part, an assessment of modeled air
quality in 2012 and 2014. EPA first identified the following two sets
of downwind receptors: (1) Receptors that EPA projects will have
nonattainment problems; and, (2) receptors that EPA projects may have
difficulty maintaining the NAAQS based on historic variation in air
quality. To identify areas that may have problems attaining or
maintaining these air quality standards, EPA projected a suite of
future air quality design values, based on measured data during the
period 2003 through 2007. EPA used the average of these future design
values to assess whether an area will be in nonattainment. EPA used the
maximum projected future design value to assess whether an area may
have difficulty maintaining the relevant NAAQS (i.e., whether an area
has a reasonable possibility of being in nonattainment under adverse
emission and weather conditions). Section V.C of this preamble details
the Transport Rule's approach to identify downwind nonattainment and
maintenance areas.
After identifying downwind nonattainment and/or maintenance areas,
EPA next used air quality modeling to determine which upwind states are
projected to contribute at or above threshold levels to the air quality
problems in those areas. Section V.D details the choice of air quality
thresholds and the approach to determine how much each upwind state
contributes. States whose contributions meet or exceed the threshold
levels were analyzed further, as detailed in section VI, to determine
whether they significantly contribute to nonattainment or interfere
with maintenance of a relevant NAAQS, and if so, the quantity of
emissions that constitute their significant contribution and
interference with maintenance.
When EPA proposed this air-quality and cost-based multi-factor
approach to identify emissions that constitute significant contribution
to nonattainment and interference with maintenance from upwind states
with respect to the 1997 ozone, annual PM2.5, and 2006 24-
hour PM2.5 NAAQS, the Agency indicated that the approach was
designed to be applicable to both current and potential future ozone
and PM2.5 NAAQS (75 FR 45214). EPA believes that the
Transport Rule's approach of using air-quality thresholds to determine
upwind-to-downwind-state linkages and using the air-quality and cost-
based multi-factor approach to determine the quantity of emissions that
each upwind state must eliminate, i.e., the state's significant
contribution to nonattainment and interference with maintenance, could
serve as a precedent for quantifying upwind state emission reduction
responsibilities with respect
[[Page 48212]]
to potential future NAAQS, as discussed further in section VI.A of this
preamble. The Agency further believes that the final Transport Rule
demonstrates the strong value of this approach for addressing the role
of interstate transport of air pollution in communities' ability to
comply with current and future NAAQS.
EPA thus identified specific emission reduction responsibilities
for each upwind state found to significantly contribute to
nonattainment or interfere with maintenance in other states. Using that
information, EPA developed individual state budgets for emissions from
covered units under the Transport Rule. The Transport Rule emission
budgets are based on EPA's state-by-state analysis of each upwind
state's significant contribution to nonattainment and interference with
maintenance. Because each state's budget is directly linked to this
state-specific analysis of the state's obligations pursuant to section
110(a)(2)(D)(i)(I), this approach addresses the Court's concerns about
the development of CAIR budgets.
In this rule, EPA is finalizing SO2 and annual
NOX budgets for each state covered for the 24-hour and/or
annual PM2.5 NAAQS and an ozone-season NOX budget
for each state covered for the ozone NAAQS. A state's emission budget
is the quantity of emissions that will remain from covered units under
the Transport Rule after elimination of significant contribution to
nonattainment and interference with maintenance in an average year
(i.e., before accounting for the inherent variability in power system
operations).\7\
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\7\ For the states discussed above for which EPA has quantified
the minimum amount of emission reductions needed to make measurable
progress toward satisfying the state's section 110(a)(2)(D)(i)(I)
responsibility, the emission budget is the quantity of emissions
that will remain from covered units after removal of those
emissions.
---------------------------------------------------------------------------
Baseline power sector emissions from a state can be affected by
changing weather patterns, demand growth, or disruptions in electricity
supply from other units or from the transmission grid. As a
consequence, emissions could vary from year to year even in a state
where covered sources have installed all controls and taken all
measures necessary to eliminate the state's significant contribution to
nonattainment and interference with maintenance. As described in detail
in sections VI and VII of this preamble, the Transport Rule accounts
for the inherent variability in power system operations through
``assurance provisions'' based on state-specific variability limits
which extend above the state budgets to form each state's ``assurance
level.'' The state assurance levels take into account the inherent
variability in baseline emissions from year to year. The final
Transport Rule FIPs will implement assurance provisions starting in
2012 as discussed in section VII, below.
The emission reduction requirements (i.e., the ``remedy'') EPA is
promulgating in this rule respond to the Court's concerns that in CAIR,
EPA had not shown that the emission reduction requirements would get
all necessary reductions within the state as required by section
110(a)(2)(D)(i)(I). The Transport Rule FIPs include assurance
provisions specifically designed to ensure that no state's emissions
are allowed to exceed that specific state's budget plus the variability
limit (i.e., the state's assurance level).
Each state's Transport Rule SO2, annual NOX,
or ozone-season NOX emission budget is composed of a number
of emission allowances (``allowances'') equivalent to the tonnage of
that specific state budget. Under the Transport Rule FIPs, EPA is
distributing (``allocating'') allowances under each state's budget to
covered units in that state. In this rule, EPA analyzed each individual
state's significant contribution to nonattainment and interference with
maintenance and calculated budgets that represent each state's
emissions after the elimination of those prohibited emissions in an
average year. The methodology used to allocate allowances to individual
units in a particular state has no impact on that state's budget or on
the requirement that the state's emissions not exceed that budget plus
the variability limit; the allocation methodology therefore has no
impact on the rule's ability to satisfy the statutory mandate of CAA
section 110(a)(2)(D)(i)(I).
The Transport Rule's approach to allocate emission allowances to
existing units is based on historic heat-input data, as detailed in
section VII.D of this preamble. The Transport Rule SO2,
annual NOX, and ozone-season NOX emission
allowances each authorize the emission of one ton of SO2,
annual NOX, or ozone-season NOX emissions,
respectively, during a Transport Rule control period, and are the
currency in the Transport Rule's air quality-assured trading programs.
As discussed in section IX.A.2 below, EPA is creating these Transport
Rule allowances as distinct compliance instruments with no relation to
allowances from the CAIR trading programs. EPA agrees with the general
principle that it is desirable, where possible, to provide continuity
under successive regulatory trading programs, for example through the
carryover of allowances from one program into a subsequent one.
However, EPA is promulgating the Transport Rule as a court-ordered
replacement for (not a successor to) CAIR's trading programs. In light
of the specific circumstances of this case, including legal and
technical issues discussed in Section IX.A.2 below, the final rule will
not allow any carryover of banked SO2 or NOX
allowances from the Title IV or CAIR trading programs. EPA will
strongly consider administrative continuity of this rule's trading
programs under any future actions designed to address related problems
of interstate transport of air pollution. A state may submit a SIP
revision under which the state (rather than EPA) would determine
allocations for one or more of the Transport Rule trading programs
beginning with vintage year 2013 or later allowances.\8\ Section X of
this preamble discusses the final rule's provisions for SIP submissions
in detail.
---------------------------------------------------------------------------
\8\ This final rule allows states to make 2013 allowance
allocations through the use of a SIP revision that is narrower in
scope than the other SIP revisions states can use to replace the
FIPs and/or to make allocation decisions for 2014 and beyond, as
discussed in section X.
---------------------------------------------------------------------------
Table III-1 lists states covered by the Transport Rule for
PM2.5 and ozone. It also, with respect to PM2.5,
identifies whether EPA determined the state was significantly
contributing to nonattainment or interfering with maintenance of the
1997 annual PM2.5 NAAQS, the 2006 24-hour PM2.5
NAAQS, or both. As discussed below, the Transport Rule sorts the states
required to reduce SO2 emissions due to their contribution
to PM2.5 downwind into two groups of varying reduction
stringency, with ``Group 1'' states subject to greater SO2
reduction stringency than ``Group 2'' states starting in 2014. Table
III-1 also lists which SO2 Group each of the states is in.
[[Page 48213]]
Table III-1--States That Significantly Contribute to Nonattainment or Interfere With Maintenance of a NAAQS
Downwind in the Final Transport Rule
----------------------------------------------------------------------------------------------------------------
1997 Annual PM2.5 2006 24-Hour
State 1997 Ozone NAAQS NAAQS PM2.5 NAAQS SO2 group
----------------------------------------------------------------------------------------------------------------
Alabama............................. X X X 2
Arkansas............................ X ................. ................. .................
Florida............................. X ................. ................. .................
Georgia............................. X X X 2
Illinois............................ X X X 1
Indiana............................. X X X 1
Iowa................................ ................. X X 1
Kansas.............................. ................. ................. X 2
Kentucky............................ X X X 1
Louisiana........................... X ................. ................. .................
Maryland............................ X X X 1
Michigan............................ ................. X X 1
Minnesota........................... ................. ................. X 2
Mississippi......................... X ................. ................. .................
Missouri............................ ................. X X 1
Nebraska............................ ................. ................. X 2
New Jersey.......................... X ................. X 1
New York............................ X X X 1
North Carolina...................... X X X 1
Ohio................................ X X X 1
Pennsylvania........................ X X X 1
South Carolina...................... X X ................. 2
Tennessee........................... X X X 1
Texas............................... X X ................. 2
Virginia............................ X ................. X 1
West Virginia....................... X X X 1
Wisconsin........................... ................. X X 1
Number of States.................... 20 18 21 .................
----------------------------------------------------------------------------------------------------------------
As explained in this preamble, EPA has improved and updated both
steps of its significant contribution analysis. It updated and improved
the modeling platforms and modeling inputs used to identify states with
contributions to certain downwind receptors that meet or exceed
specified thresholds. It also updated and improved its analysis for
identifying any emissions within such states that constitute the
state's significant contribution to nonattainment or interference with
maintenance. Therefore, the results of the analysis conducted for the
final rule differ somewhat from the results of the analysis conducted
for the proposal.\9\
---------------------------------------------------------------------------
\9\ EPA updated its modeling platforms and modeling inputs in
response to public comments received on the proposed Transport Rule
and subsequent NODAs and performed other standard updates.
---------------------------------------------------------------------------
With respect to the 1997 ozone NAAQS, the analysis EPA conducted
for the proposal did not identify Wisconsin, Iowa and Missouri as
states that significantly contribute to nonattainment or interfere with
maintenance of the ozone NAAQS in another state. However, the analysis
conducted for the final rule shows that emissions from these states do
significantly contribute to nonattainment or interfere with maintenance
of the ozone NAAQS in another state. EPA is not issuing FIPs with
respect to the 1997 ozone NAAQS or finalizing ozone season
NOX budgets for these states in this rule. EPA is publishing
a supplemental notice of proposed rulemaking that will provide an
opportunity for public comment on our conclusion that these states
significantly contribute to nonattainment or interfere with maintenance
of the 1997 ozone NAAQS.
In the other direction, the analysis conducted for the proposal
supported EPA's conclusion at the time that Connecticut, Delaware, and
the District of Columbia significantly contributed to nonattainment or
interfered with maintenance with respect to the 1997 ozone NAAQS,
whereas the modeling for the final rule no longer supports that
conclusion for those states.
Additionally, the modeling conducted for the final rule identified
two ozone maintenance receptors that were not identified in the
modeling conducted for the proposal--Allegan County (MI) and Harford
County (MD). Five states that EPA identified as significantly
contributing to maintenance problems at the Allegan and/or Harford
County receptors in the modeling for the final rule uniquely contribute
to these receptors, i.e., absent these receptors the states would not
be covered by the Transport Rule ozone-season program. The five states
that uniquely contribute to these receptors are Iowa, Kansas, Michigan,
Oklahoma, and Wisconsin. EPA is not issuing FIPs with respect to the
1997 ozone NAAQS or finalizing ozone-season NOX budgets for
these states in this rule. EPA is publishing a supplemental notice of
proposed rulemaking that will provide an opportunity for public comment
on our conclusion that these states significantly contribute to
nonattainment or interfere with maintenance of the 1997 ozone NAAQS.
EPA did not change its methodology between the proposed Transport
Rule and the final Transport Rule for identifying upwind states that
significantly contribute to nonattainment or interfere with maintenance
in other states; nor did EPA change its methodology for identifying
receptors of concern with respect to maintenance of the 1997 ozone
NAAQS. The final rule's air quality modeling identifies the new states
and new receptors described above based on updated input information
(including emission inventories), much of which was provided to EPA
through public comment on the proposal and subsequent NODAs. Section V
of this preamble details the approach EPA used
[[Page 48214]]
to identify contributing states and receptors of concern.
With respect to the annual PM2.5 NAAQS, the analysis EPA
conducted for the proposal supported EPA's conclusion that the states
of Delaware, the District of Columbia, Florida, Louisiana, Minnesota,
New Jersey, and Virginia were significantly contributing to
nonattainment and interfering with maintenance of the annual
PM2.5 NAAQS while the final rule's analysis does not. Also,
with respect to the 24-hour PM2.5 NAAQS, the analysis
conducted for the proposal supported EPA's conclusion that the states
of Connecticut, Delaware, the District of Columbia, and Massachusetts
were significantly contributing to nonattainment or interfering with
maintenance in other states while the analysis conducted for the final
rule did not.
In the proposal EPA also requested comment on whether Texas should
be included in the Transport Rule for annual PM2.5. EPA's
analysis for the proposal showed that emissions in Texas would
significantly contribute to nonattainment or interfere with maintenance
of the annual PM2.5 NAAQS if Texas were not included in the
rule for PM2.5. The proposal did not include an illustrative
budget for Texas or illustrative allowance allocations. However, the
budgets and allowance allocations provided for other states in the
proposal were included solely to illustrate the result of applying
EPA's proposed methodology for quantifying significant contribution to
the data EPA proposed to use. EPA provided an ample opportunity for
comment on this methodology and on the data, including data regarding
emissions from Texas sources, used in the significant contribution
analysis. EPA received numerous comments on and corrections to Texas-
specific data. The modeling conducted for the final rule demonstrates
that Texas significantly contributes to nonattainment or interferes
with maintenance of the annual PM2.5 NAAQS in another state.
EPA provided a full opportunity for comment on whether Texas should be
included in the rule for annual PM2.5, as well as on the
methodology and data used for the significant contribution analysis for
the final rule. EPA therefore believes its determination that Texas
must be included in the rule for annual PM2.5 is a logical
outgrowth of its proposal.
With respect to the 24-hour PM2.5 NAAQS, the analysis
EPA conducted for the proposal did not identify Texas as a state that
significantly contributes to nonattainment or interferes with
maintenance of 24-hour PM2.5 in another state. However, the
analysis conducted for the final rule shows that emissions from Texas
do significantly contribute to nonattainment of the 24-hour
PM2.5 NAAQS in another state. EPA is not issuing a FIP for
Texas with respect to the 24-hour PM2.5 NAAQS in this rule.
However, EPA believes that the FIP for Texas with respect to the 1997
annual PM2.5 NAAQS also addresses the emissions in Texas
that significantly contribute to nonattainment and interference with
maintenance of the 2006 24-hour PM2.5 NAAQS in another
state.
The final rule, however, does not cover the states of Connecticut,
Delaware, the District of Columbia, Florida, Louisiana, or
Massachusetts for annual or 24-hour PM2.5 as the analysis
for the final rule does not support their inclusion.
The Transport Rule FIPs require the 23 states covered for purposes
of the 24-hour and/or annual PM2.5 NAAQS to reduce
SO2 and annual NOX emissions by specified
amounts. The FIPs require the 20 states covered for purposes of the
ozone NAAQS to reduce ozone-season NOX emissions by
specified amounts. As discussed in detail in section VI, below, the 23
states covered for the 24-hour and/or annual PM2.5 NAAQS are
grouped in two tiers reflecting the stringency of SO2
reductions required to eliminate that state's significant contribution
to nonattainment and interference with maintenance downwind. The more-
stringent SO2 tier (``Group 1'') is comprised of the 16
states indicated in Table III-1, above, and the less-stringent
SO2 tier (``Group 2'') is comprised of the 7 states
identified in the table. The two SO2 trading programs are
exclusive, i.e., a covered source in a Group 1 state may use only a
Group 1 allowance for compliance, and likewise a source in a Group 2
state may use only a Group 2 allowance for compliance. In Group 1
states, the SO2 reduction requirements become more stringent
in the second phase, which starts in 2014.
In response to the Court's opinion in North Carolina, EPA has
coordinated the Transport Rule's compliance deadlines with the NAAQS
attainment deadlines that apply to the downwind nonattainment and
maintenance areas. The Transport Rule requires that all significant
contribution to nonattainment and interference with maintenance
identified in this action with respect to the 1997 annual
PM2.5 NAAQS and the 2006 24-hour PM2.5 NAAQS be
eliminated by no later than 2014, with an initial phase of reductions
starting in 2012 to ensure that reductions are made as expeditiously as
practicable and, consistent with the Court's remand, to ``preserve the
environmental values covered by CAIR.'' Sources must comply by January
1, 2012 and January 1, 2014 for the first and second phases,
respectively.
With respect to the 1997 ozone NAAQS, the Transport Rule requires
NOX reductions starting in 2012 to ensure that reductions
are made as expeditiously as practicable to assist downwind state
attainment and maintenance of the standard. Sources must comply by May
1, 2012. The Transport Rule's compliance schedule and alignment with
downwind NAAQS attainment deadlines are discussed in detail in section
VII below.
Table III-2 shows projected Transport Rule emissions compared to
projected base case emissions, and Table III-3 shows projected
Transport Rule emissions compared to historical emissions (i.e., 2005
emissions), for the power sector in all Transport Rule states. The
ozone-season NOX results shown in Tables III-2 and III-3 are
based on analysis of the group of 26 states that would be covered for
the ozone-season program if EPA finalizes the supplemental proposal
regarding ozone-season requirements for Iowa, Kansas, Michigan,
Missouri, Oklahoma, and Wisconsin.
Table III-2--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the Transport Rule Compared to Base Case Without
Transport Rule or CAIR **
[Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
2012 Base case 2012 Transport 2012 Emission 2014 Base case 2014 Transport 2014 Emission
emissions rule emissions reductions emissions rule emissions reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2..................................................... 7.0 3.0 4.0 6.2 2.4 3.9
Annual NOX.............................................. 1.4 1.3 0.1 1.4 1.2 0.2
[[Page 48215]]
Ozone-Season NOX........................................ 0.7 0.6 0.1 0.7 0.6 0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Note that numbers may not sum exactly due to rounding.
** As explained in section V.B, EPA's base case projections for the Transport Rule assume that CAIR is not in place.
Notes: The SO2 and annual NOX emissions in
this table reflect EGUs in the 23 states covered by this rule for
purposes of the 24-hour and/or annual PM2.5 NAAQS
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin). The ozone-season
NOX emissions reflect EGUs in the 20 states covered by
this rule for purposes of the ozone NAAQS (Alabama, Arkansas,
Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland,
Mississippi, New Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West
Virginia) and the six states that would be covered for the ozone
NAAQS if EPA finalizes its supplemental proposal (Iowa, Kansas,
Michigan, Missouri, Oklahoma, and Wisconsin).
Table III-3--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the
Transport Rule Compared to 2005 Actual Emissions
[Million tons]
----------------------------------------------------------------------------------------------------------------
2012 Emission 2014 Emission
2005 Actual 2012 Transport reductions 2014 Transport reductions
emissions rule emissions from 2005 rule emissions from 2005
----------------------------------------------------------------------------------------------------------------
SO2............................. 8.8 3.0 5.8 2.4 6.4
Annual NOX...................... 2.6 1.3 1.3 1.2 1.4
Ozone-Season NOX................ 0.9 0.6 0.3 0.6 0.3
----------------------------------------------------------------------------------------------------------------
Notes: The SO2 and annual NOX emissions in
this table reflect EGUs in the 23 states covered by this rule for
purposes of the 24-hour and/or annual PM2.5 NAAQS
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin). The ozone-season
NOX emissions reflect EGUs in the 20 states covered by
this rule for purposes of the ozone NAAQS (Alabama, Arkansas,
Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland,
Mississippi, New Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West
Virginia) and the six states that would be covered for the ozone
NAAQS if EPA finalizes its supplemental proposal (Iowa, Kansas,
Michigan, Missouri, Oklahoma, and Wisconsin).
In addition to the emission reductions shown above, EPA projects
other substantial benefits of the Transport Rule, as described in
section VIII in this preamble. EPA used air quality modeling to
quantify the improvements in PM2.5 and ozone concentrations
that are expected to result from the Transport Rule emission reductions
in 2014. The Agency used the results of this modeling to calculate the
average and peak reduction in annual PM2.5, 24-hour
PM2.5, and 8-hour ozone concentrations for monitoring sites
in the Transport Rule covered states (including the six states for
which EPA issued a supplemental proposal for ozone-season
NOX requirements) in 2014.
For annual PM2.5, the average reduction across all
monitoring sites in covered states in 2014 is 1.41 microgram per meter
cubed ([micro]g/m\3\) and the greatest reduction at a single site is
3.60 [micro]g/m\3\. For 24-hour PM2.5, the average reduction
across all monitoring sites in covered states in 2014 is 4.3 [micro]g/
m\3\ and the greatest reduction at a single site is 11.6 [micro]g/m\3\.
And finally, for 8-hour ozone, the average reduction across all
monitoring sites in covered states in 2014 is 0.3 parts per billion
(ppb) and the greatest is 3.9 ppb. See section VIII for further
information on air quality improvements.
EPA estimated the Transport Rule's costs and benefits, including
effects on sensitive and vulnerable and environmental justice
communities. Table III-4, below, summarizes some of these results.
Further discussion of the results is provided in preamble section VIII,
below, and in the Regulatory Impact Analysis (RIA). Estimates here are
subject to uncertainties discussed further in the RIA.
Table III-4.--Summary of Annual Benefits, Costs, and Net Benefits of the Final Transport Rule in 2014
[Billions of 2007$] \a\
----------------------------------------------------------------------------------------------------------------
Transport rule remedy (billions of 2007 $)
Description -------------------------------------------------------------------------
3% discount rate 7% discount rate
----------------------------------------------------------------------------------------------------------------
Social costs.......................... $0.81.............................. $0.81.
Total monetized benefits \b\.......... $120 to $280....................... $110 to $250.
Net benefits (benefits-costs)......... $120 to $280....................... $110 to $250.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for 2014, and are rounded to two significant figures.
[[Page 48216]]
\b\ The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5
and ozone and the welfare benefits associated with improved visibility in Class I areas. The reduction in
premature mortalities account for over 90 percent of total monetized PM2.5 and ozone benefits.
As a result of updated analyses and in response to public comments,
the final Transport Rule differs from the proposal in a number of ways.
The differences between proposal and final rule are discussed
throughout this preamble. Some key changes between proposal and final
rule are that EPA:
Updated emission inventories (resulting in generally lower
base case emissions). See section V.C.
Updated modeling and analysis tools (including improved
alignment between air quality estimates and air quality modeling
results). See sections V and VI.
Updated conclusions regarding which states significantly
contribute to nonattainment or interfere with maintenance of the NAAQS
in other states. See Table III-1 and sections V.D and VI.
Recalculated state budgets and variability limits, i.e.,
state assurance levels, based on updated modeling. See section VI.
Simplified variability limits for one-year application
only. See section VI.E.
Revised allocation methodology for existing and new units
and revised new unit set-asides for new units in Transport Rule states
and new units potentially locating in Indian country. See section
VII.D.
Changed start of assurance provisions to 2012 and
increased assurance provision penalties. See section VII.E.
Removed opt-in provisions. See section VII.B
Added provisions for full and abbreviated Transport Rule
SIP revisions. See section X.
EPA conducted substantial stakeholder outreach in developing the
Transport Rule, starting with a series of ``listening sessions'' in the
spring of 2009 with states, nongovernmental organizations, and
industry. EPA docketed stakeholder-related materials in the Transport
Rule docket (Docket ID No. EPA-HQ-OAR-2009-0491). The Agency conducted
general teleconferences on the rule with tribal environmental
professionals, conducted consultation with tribal governments, and
hosted a webinar for communities and tribal governments. EPA continued
to provide updates to regulatory partners and stakeholders through
several conference calls with states as well as at conferences where
EPA officials often made presentations. The Agency conducted additional
stakeholder outreach during the public comment period. EPA responded to
extensive public comments received during the public comment periods on
the proposed rule and associated NODAs.
This Transport Rule is one of a series of regulatory actions to
reduce the adverse health and environmental impacts of the power
sector. EPA is developing these rules to address judicial review of
previous rulemakings and to issue rules required by envir
